Ridgewood Energy P Fund 10-Q 2008 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, 2008
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)

Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:

Shares of LLC Membership Interest

Indicate by check mark 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, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	o	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	x
(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yeso  Nox

There is no market for the shares. As of August 5, 2008 there are 933.06 shares outstanding.

Table of Contents

		Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:
	Unaudited Condensed Balance Sheets as of June 30, 2008 and December 31, 2007	2
	Unaudited Condensed Statements of Operations for the three and six months ended June 30, 2008 and 2007	3
	Unaudited Condensed Statements of Cash Flows for the six months ended June 30, 2008 and 2007	4
	Notes to Unaudited Condensed Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	16
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

1

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	June 30, 2008			December 31, 2007
ASSETS
Current assets:
Cash and cash equivalents	$	16,879		$	13,878
Short-term investments in marketable securities		10,035			19,630
Production receivable		2,495			1,449
Other current assets		650			502
Total current assets		30,059			35,459
Salvage fund		1,126			1,111
Oil and gas properties:
Advances to operators for working interests and expenditures		334			1,866
Unproved properties		1,974			7,971
Proved properties		28,119			19,593
Less: accumulated depletion and amortization		(6,908	)		(2,332	)
Total oil and gas properties, net		23,519			27,098
Total assets	$	54,704		$	63,668
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Due to operators	$	6,684		$	3,183
Accrued expenses payable		119			121
Total current liabilities		6,803			3,304
Asset retirement obligations		782			454
Total liabilities		7,585			3,758
Commitments and contingencies (Note 8)
Members’ capital:
Manager:
Distributions		(1,299	)		(226	)
Accumulated deficit		(59	)		(1,220	)
Manager’s total		(1,358	)		(1,446	)
Shareholders:
Capital contributions (1,335 shares authorized; 933.0600 issued and outstanding)		138,344			138,344
Syndication costs		(15,898	)		(15,898	)
Distributions		(7,356	)		(1,278	)
Accumulated deficit		(66,613	)		(59,812	)
Shareholders’ total		48,477			61,356
Total members’ capital		47,119			59,910
Total liabilities and members’ capital	$	54,704		$	63,668

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

2

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

	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008			2007
Revenue
Oil and gas revenue	$	6,292		$	—		$	10,632		$	—
Expenses
Depletion and amortization		2,482			—			4,576			—
Dry-hole costs		9,224			417			10,085			3,725
Management fees to affiliate (Note 6)		512			543			1,028			1,078
Operating expenses		225			117			545			119
General and administrative expenses		221			249			405			344
Total expenses		12,664			1,326			16,639			5,266
Loss from operations		(6,372	)		(1,326	)		(6,007	)		(5,266	)
Other income
Interest income		108			618			367			1,384
Net loss	$	(6,264	)	$	(708	)	$	(5,640	)	$	(3,882	)
Manager Interest
Net income (loss)	$	687		$	(114	)	$	1,161		$	(231	)
Shareholder Interest
Net loss	$	(6,951	)	$	(594	)	$	(6,801	)	$	(3,651	)
Net loss per share	$	(7,450	)	$	(637	)	$	(7,289	)	$	(3,913	)

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

3

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

	Six months ended June 30,
	2008			2007
Cash flows from operating activities
Net loss	$	(5,640	)	$	(3,882	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depletion and amortization		4,576			—
Dry-hole costs		10,085			3,725
Accretion expense		10			3
Interest earned on marketable securities		(147	)		(860	)
Changes in assets and liabilities:
Increase in production receivable		(1,046	)		—
(Increase) decrease in other current assets		(83	)		266
Increase in accrued expenses payable		22			142
Net cash provided by (used in) operating activities		7,777			(606	)
Cash flows from investing activities
Payments to operators for working interests and expenditures		(334	)		—
Capital expenditures for oil and gas properties		(7,018	)		(23,442	)
Interest reinvested in salvage fund		(15	)		(17	)
Proceeds from the maturity of marketable securities		19,742			46,250
Investment in marketable securities		(10,000	)		(4,196	)
Net cash provided by investing activities		2,375			18,595
Cash flows from financing activities
Distributions		(7,151	)		—
Net cash used in financing activities		(7,151	)		—
Net increase in cash and cash equivalents		3,001			17,989
Cash and cash equivalents, beginning of period		13,878			23,667
Cash and cash equivalents, end of period	$	16,879		$	41,656
Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to dry-hole costs	$	1,866		$	—

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

4

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 (the “LLC Agreement”) dated as of May 16, 2005 by and among Ridgewood Energy Corporation (the “Manager”) and the shareholders of the Fund.

The Fund was organized to acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. During 2007, the Fund began earning revenue and was determined to no longer be an exploratory stage enterprise.

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 unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 6 and 8.

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, 2007 included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “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 asset retirement obligations. 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 June 30, 2008 and December 31, 2007, bank balances, inclusive of salvage fund, exceeded federally insured limits by $9.7 million and $10.7 million, respectively. The Fund maintains bank deposits with accredited financial institutions.

5

Investments in Marketable Securities
At times the Fund may purchase investments comprised of U.S. Treasury Bills and Notes. These investments are considered short-term when their maturities, when purchased, are greater than three months and one year or less, and long-term when their maturities are in excess of twelve months. The Fund currently has short-term investments that are classified as held-to-maturity. Held-to-maturity securities are those investments that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value. At June 30, 2008 the Fund had short-term held-to-maturity investments totaling $10.0 million, which mature in October 2008. At December 31, 2007, the Fund had short-term held-to-maturity investments totaling $19.6 million.

For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.

Salvage Fund
Pursuant to the Fund’s LLC Agreement, 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. At June 30, 2008 and December 31, 2007, the Fund had held-to-maturity investments within its salvage fund totaling $1.1 million. The held-to-maturity investment held within the salvage fund at June 30, 2008 matures in February 2012.

Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.

Oil and Gas Properties
Investments in oil and 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 gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and 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 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, 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. The Manager does not currently intend to sell any of the Fund’s property interests.

Capitalized acquisition costs of producing oil and gas properties are depleted by the unit-of-production method.

At June 30, 2008 amounts recorded in due to operators totaling $6.6 million related to capital expenditures for oil and gas property. These amounts were paid during the third quarter of 2008.

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 rights, 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.

6

Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. The table below presents changes in asset retirement obligations for the six months ended June 30, 2008 and the year ended December 31, 2007.

	June 30, 2008			December 31, 2007
	(in thousands)
Balance - Beginning of period	$	454		$	97
Liabilities incurred		417			892
Liabilities settled		(99	)		(542	)
Accretion expense		10			7
Balance - End of period	$	782		$	454

As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.

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 unaffiliated broker-dealers are reflected as a reduction of shareholders’ capital.

Revenue Recognition and Imbalances
Oil and natural gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable.

The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other non-current liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production. Gas imbalances are reflected as adjustments to estimates of proved gas reserves and future cash flows. At June 30, 2008 and December 31, 2007, there were no 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 Financial Accounting Standards (“SFAS”) 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. During the three and six months ended June 30, 2008 and 2007, 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. The Fund began production during the third quarter 2007.

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

7

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. Recent Accounting Standards

In May 2008, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” (“SFAS No.162”), which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with GAAP. SFAS No. 162 will be effective sixty days following the Securities and Exchange Commission’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411. The Fund does not expect the adoption of SFAS No. 162 will have a material impact on its financial condition or results of operation.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS No.157”), which applies under most other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 provides a common definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in a transaction between market participants. The new standard also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair value measurements. SFAS No. 157 had originally been effective for financial statements issued for fiscal years beginning after November 15, 2007, however the FASB has agreed on a one year deferral for all non-financial assets and liabilities. On January 1, 2008, the Fund adopted SFAS No. 157 for financial assets and liabilities.

4. 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.

The following table reflects the net changes in unproved properties for the six months ended June 30, 2008 and the year ended December 31, 2007. As of June 30, 2008, the Fund had no capitalized exploratory well costs greater than one year.

	June 30, 2008			December 31, 2007
	(in thousands)
Balance - Beginning of the period	$	7,971		$	—
Additions to capitalized exploratory well costs pending the determination of proved reserves		6,108			16,534
Reclassifications to proved properties based on the determination of proved reserves		(5,242	)		(8,563	)
Capitalized exploratory well costs charged to dry-hole costs		(6,863	)		—
Balance - End of the period	$	1,974		$	7,971

8

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. During the six months ended June 30, 2008, certain wells received credits from their respective operators upon review and audit of the wells’ costs. Dry-hole costs are detailed in the table below.

	Three months ended June 30,						Six months ended June 30,
Lease Block	2008			2007			2008			2007
	(in thousands)
High Island 38	$	6,407		$	—		$	6,407		$	—
Walker Ridge 155		2,246			—			2,246			—
West Cameron 109		—			74			599			246
Eugene Island 346/347 well #3		550			—			550			—
Mississippi Canyon 489/490		7			—			316			—
South Timbalier 135/136		9			58			7			1,688
Green Canyon 246		(2	)		330			—			1,834
Other wells		7			(45	)		(40	)		(43	)
	$	9,224		$	417		$	10,085		$	3,725

5. 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 distributions will be allocated 85% to the shareholders and 15% to the Manager, as required by 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 Fund began making distributions in December 2007. For the six months ended June 30, 2008, the Fund made distributions to the shareholders and Manager of $6.1 million and $1.1 million, respectively. There were no distributions paid during the six months ended June 30, 2007.

6. Related Parties

The Fund’s LLC 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, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for the three and six months ended June 30, 2008 were $0.5 million and $1.0 million, respectively. For the three and six months ended June 30, 2007 management fees were $0.5 million and $1.1 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 June 30, 2008 and December 31, 2007, there were no such amounts payable or receivable.

None of the compensation paid to 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.

7. Fair Value of Financial Instruments

As of June 30, 2008 and December 31, 2007, the carrying value of cash and cash equivalents, short-term investments in marketable securities, salvage fund, production receivable and accrued expenses approximates fair value.

9

8. Commitments and Contingencies

Capital Commitments
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 vary depending on the stage of development on a property-by-property basis. As of June 30, 2008, the Fund had committed to spend an additional $0.4 million related to the properties.

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, 2008 and December 31, 2007, 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. Moreover, insurance is obtained as a package covering all of the Manager’s investment programs. Claims made by other such programs can reduce or eliminate insurance for the Fund.

10

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

Cautionary Statement Regarding Forward-Looking Statements

Certain statements in this quarterly report on Form 10-Q (“Quarterly Report”) and the documents Ridgewood Energy P Fund, LLC (the “Fund”) has incorporated by reference into this Quarterly Report, other than purely historical information, including estimates, projections, statements relating to the Fund’s business plans, strategies, objectives and expected operating results, and the assumptions upon which those statements are based, are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “would,” “will be,” “will continue,” “will likely result,” and similar expressions. Forward-looking statements are based on current expectations and assumptions that are subject to risks and uncertainties which may cause actual results to differ materially from the forward-looking statements. Examples of such events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market conditions affecting the pricing of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations. The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

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 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 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 2007 Annual Report on Form 10-K.

Overview of the Fund’s Business

The Fund is a Delaware limited liability company formed on March 21, 2005 to acquire interests primarily in oil and natural gas projects located in the U.S. waters of the Gulf of Mexico. Ridgewood Energy Corporation (“Ridgewood Energy” or the “Manager”) a Delaware corporation, is the Manager. As the Manager, Ridgewood Energy has direct and exclusive control over the management and control of Fund operations. 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 management, administrative and advisory services associated with these projects. For these services, the Manager receives an annual management fee equal to 2.5% of capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, 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 fourteen wells, four that have been determined to be successful, one that is currently drilling, and nine of which have been determined to be dry holes.

11

Currently Drilling

South Timbalier 287
In November 2007, the Fund acquired a 4.0% working interest in the exploratory project South Timbalier 287 from GOM Shelf LLC (Apache Corporation) (“Apache”), the operator. South Timbalier 287 is located southwest of the Mississippi River Delta in about 480 feet of water. This project started drilling in March 2008 and results are expected in August 2008. Through June 30, 2008, the Fund has spent $2.3 million, inclusive of advances, related to this property, for which the total estimated budget is $2.6 million.

Successful Projects

Eugene Island 346/347
Well #1
In March 2007, the Fund acquired a 10% working interest in the exploratory project Eugene Island 346/347 from Newfield Exploration Company (“Newfield”), the operator. In June 2007, the well was determined to be successful. 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. The well was completed and production commenced in June 2008. Through June 30, 2008, the Fund has spent $7.0 million related to this well.

Well #2
As a result of the drilling success of the first exploratory well for Eugene Island 346/347, the second and third wells commenced drilling in May 2008. In late-May 2008, Eugene Island 346/347 well #2 was determined to be commercially successful and production commenced in July 2008. Through June 30, 2008, the Fund has spent $1.2 million related to this well, for which the total estimated budget is $1.3 million.

Eugene Island 354
In May 2007, the Fund acquired a 33% working interest in the exploratory project Eugene Island 354 from Devon Energy Production Company, L.P. (“Devon”), the operator. In June 2007, the well was determined to be successful. Completion efforts have concluded and production began in November 2007. The Fund has spent $5.1 million related to this property.

West Cameron 593
In July 2006, the Fund acquired a 43.3% working interest in the exploratory project West Cameron 593 from Newfield Exploration Company (“Newfield”), the operator. West Cameron 593 was determined to be successful in 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 Fund has spent $14.1 million related to this property.

Dry Holes

Eugene Island 346/347 Well #3
In June 2008, the Fund was informed by McMoRan that Eugene Island 346/347 well #3 did not have commercially productive quantities of either natural gas or oil and had been determined to be an unsuccessful well, or dry hole. As a result of this dry hole, the Fund recorded dry-hole costs of $0.6 million during the six months ended June 30, 2008.

Walker Ridge 155
In 2007 the Fund acquired a 1.0% working interest in the exploratory project Walker Ridge 155 from Kerr-McGee Oil & Gas Corporation (“Kerr McGee”), a wholly owned subsidiary of Anadarko Petroleum Corporation (“Anadarko”), the operator of the project. Drilling for Walker Ridge 155, a deepwater project began in mid-August 2007.

On June 3, 2008, the Fund was informed by Anadarko that based upon its evaluation of the three-dimensional data surrounding the Walker Ridge 155 lease block, they have elected not to continue drilling this well. The well has been determined to be unsuccessful, or a dry hole, and has been plugged and abandoned. Dry-hole costs related to this well, including plug and abandonment expenses, for the six months ended June 30, 2008 were $2.2 million.

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High Island 38
In the fourth quarter 2007, the Fund acquired a 12.5% working interest in the High Island 38 project, which is operated by W&T Offshore, Inc. (“W&T Offshore”). In June 2008, the well was determined to be unsuccessful, or a dry hole, and has been plugged and abandoned. Dry-hole costs related to this well, including plug and abandonment expenses, for the six months ended June 30, 2008 were $6.4 million.

Mississippi Canyon 489/490
In the third quarter 2007, the Fund acquired an 8.33% working interest in the exploratory project Mississippi Canyon 489/490 from LLOG Exploration Offshore, Inc. (“LLOG”), the operator. Drilling began in September 2007, and in November 2007 the operator informed the Fund that Mississippi Canyon 489/490 did not have commercially productive quantities of either oil or natural gas and had been determined to be an unsuccessful well, or dry hole. Dry-hole costs related to this well, including plug and abandonment expenses, were $3.5 million, of which $0.3 million were incurred during the six months ended June 30, 2008.

Results of Operations

The following review of operations for the three and six months ended June 30, 2008 and 2007 should be read in conjunction with the Fund’s financial statements and the notes thereto.

	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008			2007
	(in thousands)
Revenue
Oil and gas revenue	$	6,292		$	—		$	10,632		$	—
Expenses
Depletion and amortization		2,482			—			4,576			—
Dry-hole costs		9,224			417			10,085			3,725
Management fees to affiliate		512			543			1,028			1,078
Operating expenses		225			117			545			119
General and administrative expenses		221			249			405			344
Total expenses		12,664			1,326			16,639			5,266
Loss from operations		(6,372	)		(1,326	)		(6,007	)		(5,266	)
Other income
Interest income		108			618			367			1,384
Net loss	$	(6,264	)	$	(708	)	$	(5,640	)	$	(3,882	)

Oil and Gas Revenue. The Fund currently has three wells in production, West Cameron 593, Eugene Island 354 and Eugene Island 346/347 well #1, which began producing in September 2007, November 2007, and June 2008, respectively. Prior to September 2007, the Fund had no operating revenue and was considered an exploratory stage enterprise. Oil and gas revenue for the three and six months ended June 30, 2008 were $6.3 million and $10.6 million, respectively.

During the three and six months ended June 30, 2008, the Fund’s wells produced and sold 28 thousand barrels and 52 thousand barrels of oil, respectively, and 232 thousand mcf and 452 thousand mcf of natural gas, respectively. Oil prices have averaged $126 per barrel and $112 per barrel, respectively, during the three and six months ended June 30, 2008. Natural gas prices have averaged $11.39 per mcf and $10.68 per mcf, during the three and six months ended June 30, 2008, respectively.

Depletion and Amortization. For the three and six months ended June 30, 2008, depletion and amortization was $2.5 million and $4.6 million respectively. The Fund’s producing wells, West Cameron 593, Eugene Island 354, and Eugene Island 346/347 well #1 began production in September 2007, November 2007 and June 2008, respectively. Prior to September 2007, the Fund did not have production and therefore did not have depletion and amortization expense.

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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 six months ended June 30, 2008, certain wells received credits from their respective operators upon review and audit of the wells’ costs.

	Three months ended June 30,						Six months ended June 30,
Lease Block	2008			2007			2008			2007
	(in thousands)
High Island 38	$	6,407		$	—		$	6,407		$	—
Walker Ridge 155		2,246			—			2,246			—
West Cameron 109		—			74			599			246
Eugene Island 346/347 well #3		550			—			550			—
Mississippi Canyon 489/490		7			—			316			—
South Timbalier 135/136		9			58			7			1,688
Green Canyon 246		(2	)		330			—			1,834
Other wells		7			(45	)		(40	)		(43	)
	$	9,224		$	417		$	10,085		$	3,725

Management Fees to Affiliate. For each of the three months ended June 30, 2008 and 2007, the Fund incurred management fees of $0.5 million, respectively, representing 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. The Fund incurred $1.0 million and $1.1 million for the six months ended June 30, 2008 and 2007, respectively. The management fee, payable monthly to the Manager, is for 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.

Operating Expenses. Operating expenses represent the costs of operating and maintaining wells and related facilities, geological costs and accretion expense. For the three and six months ended June 30, 2008, operating expenses were $0.2 million and $0.5 million, respectively. For each of the three and six months ended June 30, 2007, operating expenses were $0.1 million, attributable to geological costs for Eugene Island 354. The increases during the three and six months ended June 30, 2008 were attributable to the onset of production for the Fund’s properties.

General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, as detailed in the schedule below.

	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
	(in thousands)
Insurance	$	112	$	171	$	210	$	198
Accounting fees		97		53		168		97
Trust fees and other		12		25		27		49
	$	221	$	249	$	405	$	344

Insurance expense represents premiums related to well control insurance, which varies dependent upon drilling activity, and directors and officers liability policy, which is allocated by the Manager to the Fund based on capital raised by the Fund to total capital raised by all oil and natural gas funds managed by the Manager. Accounting fees represent annual audit and tax preparation fees, quarterly reviews and filing fees of the Fund. Trust fees represent bank fees associated with the management of the Fund’s investment portfolio in U.S. Treasury securities.

Interest Income. Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities. For the three months ended June 30, 2008, interest income was $0.1 million, a $0.5 million decrease from the three months ended June 30, 2007. For the six months ended June 30, 2008, interest income was $0.4 million, a $1.0 million decrease from the six months ended June 30, 2007. The decreases were attributable to a reduction in interest rates during the three and six months ended June 30, 2008 coupled with a decrease in average outstanding balances earning interest due to capital expenditures during the period.

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Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the six months ended June 30, 2008 were $7.8 million, which were principally attributable to revenue receipts of $9.6 million and interest income received of $0.2 million. These amounts were partially offset by management fees of $1.0 million, operating expenses totaling $0.5 million, general and administrative expenses of $0.4 million, and unfavorable working capital of $0.1 million.

Cash flow used in operating activities for the six months ended June 30, 2007 was $0.6 million. Management fees of $1.1 million and general and administrative and operating expenses of $0.5 million, were offset by interest income received of $0.9 million

Investing Cash Flows

Cash flows provided by investing activities for the six months ended June 30, 2008 were $2.4 million related to proceeds from the maturity of U.S. Treasury securities totaling $19.7 million, partially offset by $10.0 million reinvested in marketable securities and capital expenditures for oil and gas properties totaling $7.4 million, inclusive of advances. Additionally, in the six months ended June 30, 2008, the Fund increased its salvage fund investments by $15 thousand, which consisted of the interest earned on this account.

Cash flows provided by investing activities for the six months ended June 30, 2007 were $18.6 million, related to proceeds from the maturity of U.S. Treasury Securities of $46.3 million, partially offset by investments in capital expenditures for oil and gas properties of $23.4 million and the purchase of U.S. Treasury Securities of $4.2 million.

Financing Cash Flows

Cash flows used in financing activities were $7.2 million for six months ended June 30, 2008 related to the payment of Manager and shareholder distributions.

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

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, 2008, the Fund had commitments related to participation agreements totaling $0.4 million for properties.

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 and infrastructure anticipated. 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.

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its 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, is equal to 2.5% of total capital contributed by shareholders, net of cumulative dry-hole and related well costs incurred.

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With respect to the payment of management fees, 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 expected to be sufficient to cover Fund expenses, including the management fee. However in periods of declining interest rates, and as the Fund expends its capital on projects, interest and/or dividend income may not be sufficient, which would require the Fund to use capital contributions to fund such expenses. Generally, it can take anywhere from 18 to 24 months to bring a project to production. Once a well is on production, the management fee and fund expenses are paid from operating income. Although the management fee can be paid out of capital contributions, this is not the Fund’s intent. Over time, as a well produces, the Fund may recover a portion of or the entire management fee that may have been paid out of capital contributions.

Distributions are funded from cash flow from operations, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and Fund operations.

The 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.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements as of June 30, 2008 and December 31, 2007 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, 2008 and December 31, 2007 other than those discussed in “Estimated Capital Expenditures” above.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, the Fund carried out an evaluation, under the supervision and with the participation of management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of June 30, 2008.

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended June 30, 2008 that has materially affected, or is 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

Not required.

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

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 Fund and Kathleen P. McSherry, Chief Financial Officer of the Fund.

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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 5, 2008			RIDGEWOOD ENERGY P FUND, LLC
	By:	/s/	ROBERT E. SWANSON
		Name:	Robert E. Swanson
		Title:	President and Chief Executive Officer
			(Principal Executive Officer)
Dated: August 5, 2008
	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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