Ridgewood Energy P Fund 10-Q 2010 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 2010

or

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from _______________________to____________________________

Commission File No.  000-51926

RIDGEWOOD ENERGY P FUND, LLC

(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization) 86-1133315 (I.R.S. Employer Identification No.)

14 Philips Parkway, Montvale, NJ  07645

(Address of principal executive offices) (Zip code)

(800) 942-5550

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes ý  No  o     

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).   Yes o      No o

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

As of August 3, 2010 the Fund had 933.06 shares of LLC Membership Interest outstanding.

Table of Contents
			Page
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements:		1
		Unaudited Condensed Balance Sheets as of June 30, 2010 and December 31, 2009	1
		Unaudited Condensed Statements of Operations for the three and six months ended June 30, 2010 and 2009	2
		Unaudited Condensed Statements of Cash Flows for the six months ended June 30, 2010 and 2009	3
		Notes to Unaudited Condensed Financial Statements	4
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		10
Item 3.	Quantitative and Qualitative Disclosures about Market Risk		16
Item 4.	Controls and Procedures		16
PART II - OTHER INFORMATION
Item 1.	Legal Proceedings		16
Item 1A.	Risk Factors		16
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		16
Item 3.	Defaults Upon Senior Securities		16
Item 4.	(Removed and Reserved)		16
Item 5.	Other Information		16
Item 6.	Exhibits		17
SIGNATURES			17

PART I - FINANCIAL INFORMATION
ITEM 1.  FINANCIAL STATEMENTS
RIDGEWOOD ENERGY P FUND, LLC
UNAUDITED CONDENSED BALANCE SHEETS
(in thousands, except share data)
	June 30, 2010			December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	1,672		$	7,436
Short-term investment in marketable securities		4,003			-
Production receivable		724			890
Other current assets		263			188
Total current assets		6,662			8,514
Salvage fund		1,354			1,340
Oil and gas properties:
Advances to operators for working interests and expenditures		54			-
Unproved properties		-			989
Proved properties		38,074			35,775
Less:  accumulated depletion and amortization		(21,931	)		(18,625	)
Total oil and gas properties, net		16,197			18,139
Total assets	$	24,213		$	27,993
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Due to operators	$	305		$	868
Accrued expenses		66			140
Total current liabilities		371			1,008
Asset retirement obligations		1,273			1,172
Total liabilities		1,644			2,180
Commitments and contingencies (Note 9)
Members' capital:
Manager:
Distributions		(3,207	)		(2,739	)
Retained earnings		1,040			599
Manager's total		(2,167	)		(2,140	)
Shareholders:
Capital contributions (1,335 shares authorized;
933.06 issued and outstanding)		138,344			138,344
Syndication costs		(15,898	)		(15,898	)
Distributions		(18,181	)		(15,526	)
Accumulated deficit		(79,529	)		(78,967	)
Shareholders' total		24,736			27,953
Total members' capital		22,569			25,813
Total liabilities and members' capital	$	24,213		$	27,993

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

1

RIDGEWOOD ENERGY P FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Revenue
Oil and gas revenue	$	2,102		$	1,021		$	4,498		$	1,878
Expenses
Depletion and amortization		1,310			1,239			3,306			2,437
Dry-hole costs		(103	)		118			(95	)		468
Impairment of proved properties		-			-			-			905
Management fees to affiliate (Note 7)		415			422			830			849
Operating expenses		207			404			537			605
General and administrative expenses		66			103			125			229
Total expenses		1,895			2,286			4,703			5,493
Income (loss) from operations		207			(1,265	)		(205	)		(3,615	)
Other (loss) income
Interest income		9			12			17			30
Derivative instrument (loss) income		(70	)		-			67			-
Total other (loss) income		(61	)		12			84			30
Net income (loss)	$	146		$	(1,253	)	$	(121	)	$	(3,585	)
Manager Interest
Net income (loss)	$	192		$	2		$	441		$	(5	)
Shareholder Interest
Net loss	$	(46	)	$	(1,255	)	$	(562	)	$	(3,580	)
Net loss per share	$	(49	)	$	(1,345	)	$	(602	)	$	(3,837	)

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

2

RIDGEWOOD ENERGY P FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
	Six months ended June 30,
	2010			2009
Cash flows from operating activities
Net loss	$	(121	)	$	(3,585	)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depletion and amortization		3,306			2,437
Dry-hole costs		(95	)		468
Impairment of proved properties		-			905
Accretion expense		20			15
Interest earned on marketable securities		(3	)		-
Derivative instrument income		(67	)		-
Derivative instrument settlements		52			-
Changes in assets and liabilities:
Decrease (increase) in production receivable		166			(222	)
(Increase) decrease in other current assets		(14	)		126
Increase (decrease) in due to operators		28			(365	)
(Decrease) increase in accrued expenses		(74	)		10
Net cash provided by (used in) operating activities		3,198			(211	)
Cash flows from investing activities
Payments to operators for working interests and expenditures		(54	)		(142	)
Capital expenditures for oil and gas properties		(1,771	)		(2,299	)
Investment in marketable securities		(4,000	)		-
Interest reinvested in salvage fund		(14	)		(13	)
Net cash used in investing activities		(5,839	)		(2,454	)
Cash flows from financing activities
Distributions		(3,123	)		(464	)
Net cash used in financing activities		(3,123	)		(464	)
Net decrease in cash and cash equivalents		(5,764	)		(3,129	)
Cash and cash equivalents, beginning of period		7,436			17,782
Cash and cash equivalents, end of period	$	1,672		$	14,653

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

3

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 gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.

The Manager has direct and exclusive control over the management of the Fund’s operations.  With respect to project investments, the Manager locates potential projects, conducts due diligence, negotiates with operators and completes the transactions in which the investments are made.  The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations.  Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information.  In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations.  The Manager also engages and manages the co ntractual relations with unaffiliated custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 7 and 9.

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.  Thes e unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2009 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”).  The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period.  On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, property balances, 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, deposits may be in excess of federally insured limits.  Federally insured limits of the Fund’s deposits are $250 thousand per insured financial institution.  At June 30, 2010, the Fund’s bank balances exceeded federally insured limits by $1.4 million, of which $0.8 million was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

4

Investments in Marketable Securities

At times, the Fund may invest in U.S. Treasury bills and notes.  These investments are considered short-term when their maturities are one year or less, and long-term when their maturities are greater than one year.  The Fund currently has short-term investments that are classified as held-to-maturity.  Held-to-maturity investments are those securities 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, 2010, the Fund had a short-term, held-to-maturity investment of $4.0 million, which matures in August 2010.

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

Salvage Fund

The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations.  At June 30, 2010, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity, totaling $0.2 million and $1.1 million, which mature in December 2010 and February 2012, respectively.  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

The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners.  The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.

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 oil and gas, are capitalized.  Expenditures for ongoing repairs and maintenance of producing properties are expens ed 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. Upon the sale or retirement of an unproved property, gain or loss on the sale is recognized.

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

At June 30, 2010 and December 31, 2009, amounts recorded in due to operators totaling $0.1 million and $0.7 million, respectively, related to capital expenditures for oil and gas properties.

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 may be 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 reclassified to unproved properties.

Asset Retirement Obligations

For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired.  When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred.  Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs.  As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.  The following table presents changes in asset retirement obligations for the six months ended June 30, 2010 and the year ended December 31, 2009.

5

	June 30, 2010		December 31, 2009
	(in thousands)
Balance, beginning of period	$	1,172	$	957
Liabilities incurred		81		184
Liabilities settled		-		-
Accretion expense		20		31
Balance, end of period	$	1,273	$	1,172

Syndication Costs

Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital.

Revenue Recognition and Imbalances

Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if 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 liabilities.  No receivables are recorded for those wells where the Fund has taken less than its share of production.

Derivative Instruments    

The Fund may periodically utilize derivative instruments to manage the price risk attributable to its oil and gas production.  Derivatives are carried on the balance sheet at fair value and recorded as either an asset or liability.  Changes in the fair value of the derivatives are recorded currently in earnings unless specific hedge accounting criteria are met.  At this time, the Fund has elected not to use hedge accounting for its derivatives and, accordingly, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as derivative instrument income on the statement of operations.  The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows.  See Note 4.   “Derivative Instruments,” for more information.

Impairment of Long-Lived Assets

The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review.  If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or that a permanent impairment in value has occurred.  The fair value determinations require considerable judgment and are sensitive to chan ge.  Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment. Given the volatility of oil and natural gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term.  If oil and natural gas prices decline significantly, even if only for a short period of time, it is possible that write-downs of oil and gas properties could occur.

The Fund did not record any impairments during the three and six months ended June 30, 2010.  During the six months ended June 30, 2009, the Fund recorded an impairment of $0.9 million related to West Cameron 593 as a result of lower oil and gas commodity prices.  There were no impairments recorded during the three months ended June 30, 2009.  The fair value of the impaired well was determined based on level 3 inputs, which include projected income from proved and probable reserves utilizing forward price curves, net of anticipated costs, discounted. 

6

Depletion and Amortization

Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method.  Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs.  The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline costs.

Income Taxes

No provision is made for income taxes in the financial statements.  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.

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, trust fees, depletion and amortization, which are allocated 99% to shareholders and 1% to the Manager.

3.   Recent Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance on improving disclosures about fair value measurements.  This guidance has new requirements for disclosures related to recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements in a rollforward reconciliation of Level 3 fair-value measurements. This guidance was effective for the Fund beginning January 1, 2010.  The adoption of this guidance did not have a material impact on the Fund’s financial statements.  The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, which will be effective for the Fund December 31, 2011. The a doption of the guidance is not expected to have a material impact on the Fund’s financial statements.

4.   Derivative Instruments

In January 2010, the Fund entered into a derivative contract for put options relating to the pricing of gas for a portion of its anticipated production.  The use of such derivative instruments limits the downside risk of adverse price movements.  The Fund has elected not to use hedge accounting for these derivatives and consequently, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as derivative instrument income on the statement of operations.  The estimated fair value of these contracts is based upon closing exchange prices on the New York Mercantile Exchange (“NYMEX”).  See Note 8. “Fair Value Measurements.”  The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment. The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.

The put options are carried at their fair value on the balance sheet within “Other current assets” and are settled based upon reported prices on the NYMEX.   The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis in the statement of operations under the caption “Derivative instrument income.” Settlements of derivative contracts are reflected in operating activities on the statement of cash flows.

At June 30, 2010, the Fund had outstanding derivative contracts with respect to its future production of gas that are not designated for hedge accounting as detailed in the following table.  The Fund had no derivative financial instruments prior to January 2010.

Production Period	Type of Contract	Volume in mmbtus		NYMEX Contract Price per mmbtu		Estimated  Fair Value  Asset
						(in thousands)
July 1, 2010 - October 31, 2010	Put Options		118,242	$	4.90	$	53

7

During the three months ended June 30, 2010, the Fund’s recorded derivative instrument losses of $70 thousand included unrealized losses of $118 thousand.  During the six months ended June 30, 2010, the Fund’s recorded derivative instrument income of $67 thousand included unrealized gains of $23 thousand.

5.  Oil and Gas Properties

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.  At June 30, 2010, the Fund had no unproved properties with capitalized exploratory well costs in excess of one year.

On April 20, 2010 in the Gulf of Mexico, as reported in the press, an explosion and fire occurred on the Deepwater Horizon drilling rig, which was engaged related to a BP-operated project, with which the Fund has no affiliation.  As a result of the explosion and resultant oil spill, the U.S. government has placed a six month moratorium on deepwater drilling operations in the Gulf of Mexico.   On June 22, 2010, a federal judge ruled against the U.S. government and lifted the moratorium and the 5th Circuit Court of Appeals recently affirmed the lower court’s ruling.  However, as of the date of this filing, there have been no deepwater drilling permits issued by the Bureau of Ocean Management, Regulation and Enforcement (R 20;BOE”) (formerly the Minerals Management Service).  In compliance with the court’s ruling, the Secretary of the Interior re-issued the moratorium and ordered it in place until the end of November 2010.   As of the date of this filing, neither the Fund’s producing properties nor the completion efforts for the Carrera and Raven projects have been impacted by the moratorium.

Capitalized exploratory well 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.  At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs. Dry-hole costs, inclusive of credits, are detailed in the following table.

	Three months ended June 30,					Six months ended June 30,
Lease Block	2010			2009		2010			2009
	(in thousands)
South Timbalier 287	$	-		$	118	$	58		$	446
Eagle Project		(65	)		-		(65	)		-
Other wells		(38	)		-		(88	)		22
	$	(103	)	$	118	$	(95	)	$	468

6.   Distributions

Distributions to shareholders are allocated in proportion to the number of shares held.  The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement.

Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions.  After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.

7.   Related Parties

The LLC Agreement provides that the Manager render management, administrative and advisory services.  For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund.  Management fees were $0.4 million and $0.8 million for each of the three and six months ended June 30, 2010 and 2009, respectively.

8

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

None of the 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.

8.   Fair Value Measurements

At June 30, 2010 and December 31, 2009, cash and cash equivalents, short-term investments in marketable securities, production receivable, salvage fund and accrued expenses approximate fair value.  At June 30, 2010, derivative instruments are recorded at fair value based on Level 2 inputs, as the instrument is an over-the-counter derivative with a third party.

9.   Commitments and Contingencies

Capital Commitments

The Fund has entered into multiple 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, 2010, the Fund had committed to spend an additional $2.8 million related to its investment properties, of which $1.6 million is expected to be incurred during the next twelve months.

Environmental Considerations

The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems.  The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry.  However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of p ossible future legislation, rule changes, or governmental or private claims.  At June 30, 2010 and December 31, 2009, 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 that 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 funds managed by the Manager.  Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.

10.   Subsequent Events

The Fund has assessed the impact of subsequent events through the date of issuance of its financial statements, and has concluded that there were no such events that require adjustment to, or disclosure in, the notes to the financial statements.

9

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 US Private Securities Litigation Reform Act of 1995 that are based on current expectations and assumptions and are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. You are therefore cautioned against relying on any such forward-loo king statements. Forward-looking statements can generally be identified by words such as “believe,” “project,” “expect,” “anticipate,” “estimate,” “intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will,” “will likely result,” and similar expressions and references to future periods.  Examples of events that could cause actual results to differ materially from historical results or those anticipated include weather conditions, such as hurricanes, changes in market conditions affecting the pricing of oil and natural gas, the cost and availability of equipment, and changes in governmental regulations.  Examples of forward-looking statements made herein include statements regarding future projects, investments and insurance.  Forward-looking statements made in this document speak only as of the date on which they are made .  The Fund undertakes no obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Critical Accounting Policies and Estimates

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 expense 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 disclosed in its 2 009 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 in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in 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 of the Fund’s operations.  The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development stage shallow water or deepwater projects.  However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.

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 for the management of all exploration, development and producing operations, as appropriate.  The Manager also participates in distributions.

Revenues are subject to market pricing for oil and natural gas, which has been extremely volatile, and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability.

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Business Update

Information regarding the Fund’s current projects is provided in the following table.

		Total Spent		Total
	Working	through		Estimated
	Interest	June 30, 2010		Budget		Status
		(in thousands)
Non-producing Properties
Carrera Project	2.5%	$	2,896	$	3,960	Completion efforts are ongoing.
						Production expected fourth quarter 2010.
Raven Project	6.25%	$	1,331	$	1,773	Completion efforts are ongoing.
						Production expected September 2010.
Producing Properties
Liberty Project	2.5%	$	3,839	$	3,919	Well completed and production commenced
						July 2010.
Whistler Project	11.0%	$	2,291	$	2,291	Production commenced January 2010.
Eugene Island 346/347 well #1	10.0%	$	6,992	$	7,041	Production commenced June 2008.  A late
						life recompletion is scheduled at an estimated
						cost of $50 thousand.
Eugene Island 346/347 well #2	10.0%	$	1,393	$	1,393	Production commenced July 2008.
West Cameron 593	43.3%	$	13,105	$	13,105	Production commenced September 2007.
Eugene Island 354	33.0%	$	5,092	$	6,247	Production commenced November 2007.
						Recompletion efforts to access behind
						the pipe reserves are expected to commence
						in 2012 at an estimated cost of $1.2 million.

On April 20, 2010 in the Gulf of Mexico, as reported in the press, an explosion and fire occurred on the Deepwater Horizon drilling rig, which was engaged related to a BP-operated project, with which the Fund has no affiliation.  As a result of the explosion and resultant oil spill, the U.S. government has placed a six month moratorium on deepwater drilling operations in the Gulf of Mexico.   On June 22, 2010, a federal judge ruled against the U.S. government and lifted the moratorium and the 5th Circuit Court of Appeals recently affirmed the lower court’s ruling.  However, as of the date of this filing, there have been no deepwater drilling permits issued by the Bureau of Ocean Management, Regulation and Enforcement (R 20;BOE”) (formerly the Minerals Management Service).  In compliance with the court’s ruling, the Secretary of the Interior re-issued the moratorium and ordered it in place until the end of November 2010.  As of the date of this filing, neither the Fund’s producing properties nor the completion efforts for Carrera and Raven projects have been impacted by the moratorium.   The extent to which these recent events may impact the Fund’s future results is uncertain.  The Fund cannot predict how federal and state authorities will further respond to the incident or whether additional changes in laws and regulations governing oil and gas operations in the Gulf of Mexico will result.  Such changes, if any, may impact the way the Fund conducts business and may increase the Fund’s cost of doing business.  A prolonged interruption may adversely impact the Fund’s financial position, results of operations and cash flows.

Results of Operations

The following table summarizes the Fund’s results of operations for the three and six months ended June 30, 2010 and 2009, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1 “Financial Statements” in Part I of this Quarterly Report.

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	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
	(in thousands)
Revenue
Oil and gas revenue	$	2,102		$	1,021		$	4,498		$	1,878
Expenses
Depletion and amortization		1,310			1,239			3,306			2,437
Dry-hole costs		(103	)		118			(95	)		468
Impairment of proved properties		-			-			-			905
Management fees to affiliate		415			422			830			849
Operating expenses		207			404			537			605
General and administrative expenses		66			103			125			229
Total expenses		1,895			2,286			4,703			5,493
Income (loss) from operations		207			(1,265	)		(205	)		(3,615	)
Other (loss) income
Interest income		9			12			17			30
Derivative instrument (loss) income		(70	)		-			67			-
Total other (loss) income		(61	)		12			84			30
Net income (loss)	$	146		$	(1,253	)	$	(121	)	$	(3,585	)

Overview.   During the three and six months ended June 30, 2010, the Fund had five producing wells: West Cameron 593, Eugene Island 354, Eugene Island 346/347 wells #1 and #2 and the Whistler Project.  Production commenced on these wells in September 2007, November 2007, June 2008, July 2008 and January 2010, respectively.  During the three and six months ended June 30, 2009, the Fund had two producing wells, West Cameron 593 and Eugene Island 354.  Eugene Island 354 came back onto production in June 2009 after being shut-in due to hurricane activity.  Eugene Island 346/347 wells #1 and #2 were shut-in pending completion of pipeline repairs.

Oil and Gas Revenue.  Oil and gas revenue for the three months ended June 30, 2010 was $2.1 million, a $1.1 million increase from the three months ended June 30, 2009.  The increase is primarily attributable to the impact of increased sales volumes totaling $0.8 million and increased average prices totaling $0.2 million.

Oil sales volumes were 12 thousand barrels and 9 thousand barrels for the three months ended June 30, 2010 and 2009, respectively.  The Fund’s oil prices averaged $77 per barrel during the three months ended June 30, 2010 compared to $59 per barrel during the three months ended June 30, 2009.

Gas sales volumes were 228 thousand mcf and 124 thousand mcf for the three months ended June 30, 2010 and 2009, respectively.  The Fund’s gas prices averaged $4.28 per mcf during the three months ended June 30, 2010 compared to $3.67 per mcf during the three months ended June 30, 2009.

Oil and gas revenue for the six months ended June 30, 2010 was $4.5 million, a $2.6 million increase from the six months ended June 30, 2009.  The increase is primarily attributable to the impact of increased sales volumes totaling $1.8 million and increased average prices totaling $0.9 million.

Oil sales volumes were 27 thousand barrels and 16 thousand barrels for the six months ended June 30, 2010 and 2009, respectively.  The Fund’s oil prices averaged $77 per barrel during the six months ended June 30, 2010 compared to $52 per barrel during the six months ended June 30, 2009.

Gas sales volumes were 462 thousand mcf and 247 thousand mcf for the six months ended June 30, 2010 and 2009, respectively.  The Fund’s gas prices averaged $4.55 per mcf during the six months ended June 30, 2010 compared to $4.07 per mcf during the six months ended June 30, 2009.

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The increases in volumes are primarily attributable to a full period of production for the Eugene Island 354 and Eugene Island 346/347 wells #1 and #2 during the three and six months ended June 30, 2010 compared to the three and six months ended June 30, 2009, when the wells were shut-in due to third quarter 2008 hurricane activity.  The increases in volumes are also attributable to the onset of production for the Whistler Project in January 2010.

Depletion and Amortization. Depletion and amortization for the three and six months ended June 30, 2010 was $1.3 million and $3.3 million, respectively, an increase of $0.1 million and $0.9 million from the three and six months ended June 30, 2009, respectively.  The increase in the three month period resulted from an increase in production volumes totaling $1.0 million, partially offset by a decrease in depletion rates totaling $1.0 million.  The increase in the six month period resulted from an increase in production volumes totaling $2.4 million, partially offset by a decrease in depletion rates totaling $1.5 million.  The decreases in depletion rates were primarily the result of revisions to reserve estimates, partially offset by the composite of productive wells, which included higher cost reserves.

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.   At times, the Fund receives credits on certain wells from their respective operators upon review and audit of the wells’ costs.    Dry-hole costs, inclusive of such credits, are detailed in the following table.

	Three months ended June 30,					Six months ended June 30,
Lease Block	2010			2009		2010			2009
	(in thousands)
South Timbalier 287	$	-		$	118	$	58		$	446
Eagle Project		(65	)		-		(65	)		-
Other wells		(38	)		-		(88	)		22
	$	(103	)	$	118	$	(95	)	$	468

Impairment of Proved Properties.  The Fund recorded an impairment expense of $0.9 million for the six months ended June 30, 2009 related to West Cameron 593 as a result of lower oil and gas commodity prices.  There was no impairment expense for the three and six months ended June 30, 2010 or for the three months ended June 30, 2009.

Management Fees to Affiliate. Management fees for each of the three and six months ended June 30, 2010 and 2009 were $0.4 million and $0.8 million, respectively.  An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.  

Operating Expenses.  Operating expenses include the costs of operating and maintaining wells and related facilities, geological costs and accretion expense as detailed in the following table.

	Three months ended June 30,					Six months ended June 30,
	2010			2009		2010			2009
	(in thousands)
Lease operating expense	$	239		$	284	$	505		$	477
Geological costs		7			-		61			-
Accretion expense		10			7		20			15
Workover costs		(49	)		113		(49	)		113
	$	207		$	404	$	537		$	605

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.   For the three months ended June 30, 2010, the average production cost was $0.73 per mcfe compared to $1.58 per mcfe for the three months ended June 30, 2009.  For the six months ended June 30, 2010, the average production cost was $0.74 per mcfe compared to $1.37 per mcfe for the six months ended June 30, 2009.  Geological costs for the three and six months ended June 30, 2010 were related to Eugene Island 346/347 well #1 and the Raven and Liberty projects.  Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.  During the three and six months ended June 30, 2010, the Fund received a credit related to workover costs incurred during the three and six months ended June 30, 2009.  Such costs were incurred to repair the West Cameron 593 processing facility, which had been damaged by hurricane activity.

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

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
	(in thousands)
Accounting fees	$	42	$	44	$	76	$	109
Insurance expense		22		55		45		108
Trust fees and other		2		4		4		12
	$	66	$	103	$	125	$	229

Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund.  Insurance expense represents premiums related to producing well and control of well insurance, which varies dependent upon the number of wells producing or drilling and directors’ and officers’ liability insurance.    Trust fees represent bank fees associated with the management of the Fund’s cash accounts.

Interest Income.  Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities.  Interest income for the three months ended June 30, 2010 was $9 thousand, a $3 thousand decrease from the three months ended June 30, 2009.  Interest income for the six months ended June 30, 2010 was $17 thousand, a $13 thousand decrease from the six months ended June 30, 2009.  The decrease was the result of a reduction in average outstanding balances earning interest, due to ongoing capital expenditures for oil and gas properties, coupled with lower interest rates earned.

Derivative Instrument (Loss) Income.  In January 2010, the Fund entered into a derivative contract for put options relating to the pricing of gas for a portion of its anticipated production.  The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis.  During the three months ended June 30, 2010, unrealized losses related to these contracts were $0.1 million and realized gains related to these contracts were $48 thousand.  During the six months ended June 30, 2010, unrealized gains related to these contracts were $23 thousand and realized gains related to these contracts were $43 thousand.  There was no derivative activity during the three and six months ended June 30, 2009.

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the six months ended June 30, 2010 were $3.2 million, primarily related to revenue received of $4.7 million, partially offset by management fees of $0.8 million, operating expenses of $0.5 million, and payments of general and administrative expenses of $0.2 million.

Cash flows used in operating activities for the six months ended June 30, 2009 were $0.2 million, primarily related to management fees of $0.8 million, payments for West Cameron 593 workover expenses of $0.5 million, operating expenses of $0.4 million and general and administrative expenses of $0.2 million, partially offset by revenue receipts of $1.7 million.

Investing Cash Flows

Cash flows used in investing activities for the six months ended June 30, 2010 were $5.8 million, primarily related to investments in U.S. Treasury securities of $4.0 million and capital expenditures for oil and gas properties totaling $1.8 million, inclusive of advances.

Cash flows used in investing activities for the six months ended June 30, 2009 were $2.5 million, primarily related to capital expenditures for oil and gas properties totaling $2.4 million, inclusive of advances.

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Financing Cash Flows

Cash flows used in financing activities for the six months ended June 30, 2010 were $3.1 million, related to manager and shareholder distributions.

Cash flows used in financing activities for the six months ended June 30, 2009 were $0.5 million, related to manager and shareholder distributions.

Estimated Capital Expenditures

The Fund has entered into multiple agreements for the acquisition, 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, 2010, the Fund had committed to spend an additional $2.8 million related to its investment properties, of which $1.6 million is expected to be incurred during the next twelve months.

When the Manager makes a decision to participate in an exploratory 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 an exploratory well is deemed a dry hole or if it is determined to be 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.

Capital expenditures for investment properties are funded with the capital raised by the Fund in its private placement offering, which is all the capital it will obtain.  The number of projects in which the Fund can invest will be limited, and each unsuccessful project the Fund experiences reduces its ability to generate revenue and exhaust its capital.  Typically, the Manager seeks an investment portfolio that combines high and low risk exploratory projects

Liquidity Needs

The Fund’s primary short-term liquidity needs are to fund its operations, inclusive of management fees, and capital expenditures for its investment properties.  Operations are funded utilizing operating income, existing cash on-hand, short-term investments and income earned therefrom. 

The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Generally, all or a portion of the management fee is paid from operating income and interest income, although the management fee can be paid out of capital contributions; however, this is not the Fund’s intent.

Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at June 30, 2010 and December 31, 2009 and does not anticipate the use of such arrangements in the future.

Contractual Obligations

The Fund enters into participation and operating agreements with operators.  On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities.  The Fund does not negotiate such contracts.  No contractual obligations exist at June 30, 2010 and December 31, 2009 other than those discussed in “Estimated Capital Expenditures” above.

Recent Accounting Pronouncements

See Note 3 of Notes to Unaudited Condensed Financial Statements – “Recent Accounting Standards” contained in this Quarterly Report for a discussion of recent accounting pronouncements.

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ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4.  CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Fund’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Fund’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report.  Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of June 30, 2010.

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended June 30, 2010 that has materially affected, or is reasonably likely to materially affect, the Fund’s internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

On August 16, 2006, the Manager of the Fund filed a lawsuit against the former independent registered public accounting firm for the Fund, Perelson Weiner, LLP, (“Perelson”) in New Jersey Superior Court, captioned Ridgewood Energy Corporation v. Perelson Weiner, LLP, Docket No. L-6092-06.  The suit alleged professional malpractice and breach of contract in connection with audit and accounting services performed for the Fund by Perelson. Thereafter, Perelson filed a counterclaim against the Manager on October 20, 2006, alleging breach of contract due to unpaid invoices in the amount of $326,554. During May 2010, a settlement was reached by the parties at no cost to the Fund.  Legal costs related to this claim were borne by the Manager.

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. (REMOVED AND RESERVED)

ITEM 5. OTHER INFORMATION

None.

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ITEM 6. EXHIBITS

EXHIBIT
NUMBER	TITLE OF EXHIBIT	METHOD OF FILING
31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a).	Filed herewith
31.2	Certification of Kathleen P. McSherry, Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a).	Filed herewith
32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Chief Financial Officer of the Fund.	Filed herewith

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.

				RIDGEWOOD ENERGY P FUND, LLC
Dated:	August 3, 2010	By:	/s/	ROBERT E. SWANSON
			Name:	Robert E. Swanson
			Title:	Chief Executive Officer
				(Principal Executive Officer)
Dated:	August 3, 2010	By:	/s/	KATHLEEN P. MCSHERRY
			Name:	Kathleen P. McSherry
			Title:	Executive Vice President and Chief Financial Officer
				(Principal Financial Officer)

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