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 1934For the quarterly period ended June 30, 2009


or





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





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.)





947 Linwood Avenue, Ridgewood, NJ 07450


(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 x  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
oNon-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




There is no market for the shares. As of July 30, 2009 there are 933.06 shares outstanding.












Table of ContentsPagePART I - FINANCIAL INFORMATIONItem 1.
Financial Statements
3Unaudited Condensed Balance Sheets as of June 30, 2009 and December 31, 2008
3Unaudited Condensed Statements of Operations for the three and six months ended June 30, 2009 and 2008
4Unaudited Condensed Statements of Cash Flows for the six months ended June 30, 2009 and 2008
5Notes to Unaudited Condensed Financial Statements
6Item 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
12Item 3.
Quantitative and Qualitative Disclosures about Market Risk
17Item 4.
Controls and Procedures
17PART II - OTHER INFORMATIONItem 1.
Legal Proceedings
18Item 1A.
Risk Factors
18Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
18Item 3.
Defaults Upon Senior Securities
18Item 4.
Submission of Matters to a Vote of Security Holders
18Item 5.
Other Information
18Item 6.
Exhibits
18SIGNATURES
19










2
 Table of Contents




PART I - FINANCIAL INFORMATIONITEM 1.  FINANCIAL STATEMENTSRIDGEWOOD ENERGY P FUND, LLCUNAUDITED CONDENSED BALANCE SHEETS(in thousands, except share data)June 30,


December 31,2009


2008ASSETSCurrent assets:Cash and cash equivalents

$
14,653


$
17,782Production receivable


445



223Other current assets


44



156Total current assets


15,142



18,161Salvage fund


1,152



1,139Oil and gas properties:Advances to operators for working interests and expenditures


142



-Unproved properties


23



-Proved properties


29,572



29,246Less:  accumulated depletion and amortization


(13,052
)


(9,710
)Total oil and gas properties, net


16,685



19,536Total assets

$
32,979


$
38,836LIABILITIES AND MEMBERS' CAPITALCurrent liabilities:Due to operators

$
505


$
2,338Accrued expenses


88



78Total current liabilities


593



2,416Asset retirement obligations


972



957Total liabilities


1,565



3,373Commitments and contingencies (Note 8)Members' capital:Manager:Distributions


(2,533
)


(2,464
)Retained earnings


286



291Manager's total


(2,247
)


(2,173
)Shareholders:Capital contributions (1,335 shares authorized;933.06 issued and outstanding)


138,344



138,344Syndication costs


(15,898
)


(15,898
)Distributions


(14,359
)


(13,964
)Accumulated deficit


(74,426
)


(70,846
)Shareholders' total


33,661



37,636Total members' capital


31,414



35,463Total liabilities and members' capital

$
32,979


$
38,836


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




3
 Table of Contents




RIDGEWOOD ENERGY P FUND, LLCUNAUDITED CONDENSED STATEMENTS OF OPERATIONS(in thousands, except per share data)Three months ended June 30,


Six months ended June 30,2009


2008


2009


2008RevenueOil and gas revenue

$
1,021


$
6,292


$
1,878


$
10,632ExpensesDepletion and amortization


1,239



2,482



2,437



4,576Impairment of proved properties


-



-



905



-Dry-hole costs


118



9,224



468



10,085Management fees to affiliate (Note 6)


422



512



849



1,028Operating expenses


404



225



605



545General and administrative expenses


103



221



229



405Total expenses


2,286



12,664



5,493



16,639Loss from operations


(1,265
)


(6,372
)


(3,615
)


(6,007
)Other incomeInterest income


12



108



30



367Net loss

$
(1,253
)

$
(6,264
)

$
(3,585
)

$
(5,640
)Manager InterestNet income (loss)

$
2


$
687


$
(5
)

$
1,161Shareholder InterestNet loss

$
(1,255
)

$
(6,951
)

$
(3,580
)

$
(6,801
)Net loss per share

$
(1,345
)

$
(7,450
)

$
(3,837
)

$
(7,289
)






4
 Table of Contents




RIDGEWOOD ENERGY P FUND, LLCUNAUDITED CONDENSED STATEMENTS OF CASH FLOWS(in thousands)Six months ended June 30,2009


2008Cash flows from operating activitiesNet loss

$
(3,585
)

$
(5,640
)Adjustments to reconcile net loss to net cash(used in) provided by operating activities:Depletion and amortization


2,437



4,576Impairment of proved properties


905



-Dry-hole costs


468



10,085Accretion expense


15



10Interest earned on marketable securities


-



(147
)Changes in assets and liabilities:Increase in production receivable


(222
)


(1,046
)Decrease (increase) in other current assets


126



(83
)Decrease in due to operators


(365
)


-Increase in accrued expenses


10



22Net cash (used in) provided by operating activities


(211
)


7,777Cash flows from investing activitiesPayments to operators for working interests and expenditures


(142
)


(334
)Capital expenditures for oil and gas properties


(2,299
)


(7,018
)Proceeds from the maturity of investments


-



19,742Investment in marketable securities


-



(10,000
)Interest reinvested in salvage fund


(13
)


(15
)Net cash (used in) provided by investing activities


(2,454
)


2,375Cash flows from financing activitiesDistributions paid


(464
)


(7,151
)Net cash used in financing activities


(464
)


(7,151
)Net (decrease) increase in cash and cash equivalents


(3,129
)


3,001Cash and cash equivalents, beginning of period


17,782



13,878Cash and cash equivalents, end of period

$
14,653


$
16,879Supplemental schedule of non-cash investing activitiesAdvances used for capital expenditures in oil and gas properties
reclassified to dry-hole costs

$
-


$
1,866






5
 Table of Contents





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.





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 appropriate due diligence and negotiates 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 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 Fund’s December 31, 2008 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.  The Fund has assessed the impact of subsequent events through July 30, 2009, the
date of the 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.





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 revenue and expense during the reporting
period. On an ongoing basis, the Manager reviews its estimates, including those related to 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, bank deposits may be in excess of federally insured limits.  At June 30, 2009 bank balances exceeded federally insured limits by $7.0 million, of which $6.1 million was invested in
money market accounts that invest solely in U.S. Treasury bills and notes.  Effective October 2008 through December 31, 2013, federally insured limits have been increased from $0.1 million to $0.25 million for interest bearing deposits.  Additionally, non-interest bearing deposits are fully insured through December 31, 2009, after which they will be included in the $0.25 million limits.




6
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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.  At June 30, 2009 and December 31, 2008 the Fund had no short-term investments that were 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.





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 a 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, 2009, the
Fund had held-to-maturity investments within its salvage fund totaling $1.1 million, which mature in February 2012.





Interest earned on the account will become part of the salvage fund.  There are no legal 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 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.  Upon 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 units-of-production method.





As of June 30, 2009 and December 31, 2008, amounts recorded in due to operators totaling $0.4 million and $1.9 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.  The following table presents changes in asset retirement obligations for the six months ended June 30, 2009 and the year ended December 31, 2008.




7
 Table of Contents




June 30, 2009


December 31, 2008(in thousands)Balance, beginning of period

$
957


$
454Liabilities incurred


-



426Liabilities settled


-



-Accretion expense


15



24Revisions to previous estimates


-



53Balance, end of period

$
972


$
957


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





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.





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 end of
each period.  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.  Different pricing assumptions, reserve estimates or discount rates could result in a different calculated impairment.  The Fund provides for impairments on unproved properties when it determines that the property will not be developed or a permanent impairment
in value has occurred.  Given the volatility of oil and gas prices, it is reasonably possible that the Fund’s estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term.  If oil and 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.  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.  The carrying value for West Cameron 593 of $6.0 million was written down to its fair value of $5.1 million.  The fair value of the impaired well was determined based on level 3 inputs under Statement of Financial Accounting Standard No. 157, “Fair Value Measurements”, (“SFAS No. 157”), which include projected income from proved reserve and probable reserves utilizing forward price curves, net of anticipated costs, discounted.





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.




8
 Table of Contents





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 June 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 168, “The FASB Accounting Standards CodificationTMand
the Hierarchy of Generally Accepted Accounting Principles, a replacement of FASB Statement No. 162” (“SFAS 168”), which establishes the FASB Accounting Standards CodificationTM as the source of GAAP to be applied to nongovernmental agencies.  SFAS 168 explicitly recognizes rules and interpretive releases of the SEC under authority of federal securities laws as authoritative GAAP for SEC registrants.
SFAS 168 will become effective for interim or annual periods ending after September 15, 2009.  SFAS 168 will not have a material impact on the Fund’s financial statements.





In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS 165”), which sets forth general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. SFAS 165 was adopted effective for
the second quarter of 2009 and did not have a material impact on the Fund’s financial statements.





In April 2009, the FASB issued FASB Staff Position No. SFAS 107-1 and APB No. 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1 and APB 28-1”), which requires quarterly disclosure of information about the fair value of financial instruments within the scope of SFAS
No. 107, “Disclosures about Fair Value of Financial Instruments.” FSP FAS 107-1 and APB 28-1 was adopted effective for the second quarter of 2009 and did not have a material impact on the Fund’s financial statements.





In April 2009, the FASB issued FASB Staff Position No. FAS 115-2 and 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments”(“FSP FAS 115-2 and 124-2”). FSP FAS 115-2 and 124-2 amends the other-than-temporary impairment
guidance for debt securities to make the guidance more operational and to improve the presentation and disclosure of other-than-temporary impairments on debt and equity securities in the financial statements. FSP FAS 115-2 and 124-2 does not amend existing recognition and measurement guidance related to other-than-temporary impairments of equity securities. FSP FAS 115-2 and 124-2 does not require disclosures for earlier periods presented for comparative purposes at initial adoption. In periods after
initial adoption, FSP FAS 115-2 and 124-2 requires comparative disclosures only for periods ending after initial adoption. FSP FAS 115-2 and 124-2 was adopted effective for the second quarter of 2009 and did not have a material impact on the Fund’s financial statements.





In December 2008, the SEC issued Release No. 33-8995, “Modernization of Oil and Gas Reporting,” amending oil and gas reporting requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K.  The new requirements provide for consideration of new technologies in evaluating reserves,
allow companies to disclose their probable and possible reserves to investors, report oil and gas reserves using an average price based on the prior 12-month period rather than year-end prices, and revise the disclosure requirements for oil and gas operations.  The final rules are effective for fiscal years ending on or after December 31, 2009.





In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS 157”), which applies under most other accounting pronouncements that require or permit fair value measurements. SFAS 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. SFAS 157 also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair value measurements.  In February 2008, the FASB issued FASB Staff Position No. FAS 157-2, “Effective Date of FASB Statement No. 157” (“SFAS 157-2”).  SFAS 157-2 delayed the effective date of SFAS 157 for all non-financial assets and non-financial liabilities, except those that are recognized
or disclosed at fair value in the financial statements on a recurring basis (at least annually). The Fund adopted SFAS 157 for financial assets and financial liabilities effective January 1, 2008 and for non-financial assets and non-financial liabilities effective January 1, 2009, which includes applying the provisions of SFAS 157 to (i) other non-financial assets measured at fair value in conjunction with impairment assessments; and (ii) asset retirement obligations initially measured at fair value. The adoption
did not have a material impact on the Fund’s balance sheet, statement of operations, or statement of cash flows.




9
 Table of Contents





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.  At June 30, 2009 the Fund had no properties
with capitalized exploratory well costs in excess of one year.  The following table reflects the net changes in unproved properties for the six months ended June 30, 2009 and the year ended December 31, 2008.




June 30, 2009


December 31, 2008(in thousands)Balance, beginning of period

$
-


$
7,971Additions to capitalized exploratory well costspending the determination of proved reserves


23



5,444Reclassifications to proved properties based onthe determination of proved reserves


-



(9,646
)Capitalized exploratory well costs charged todry-hole costs


-



(3,769
)Balance, end of period

$
23


$
-





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.  During the three and six months ended June 30, 2009 and 2008, the Fund received 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

2009


2008


2009


2008(in thousands)South Timbalier 287

$
118


$
-


$
446


$
-High Island 38


-



6,407



19



6,407Mississippi Canyon 489/490


17



7



17



316Eugene Island 346/347 well #3


-



550



4



550West Cameron 109


-



-



-



599Walker Ridge 155


-



2,246



(4
)


2,246Other wells


(17
)


14



(14
)


(33
)$
118


$
9,224


$
468


$
10,085


5.   Distributions





Distributions to shareholders are allocated in proportion to the number of shares held.  Certain shares have early investment incentive and advance distribution rights, as defined in the LLC Agreement, which range from approximately $6 thousand to $12 thousand per share.  The Fund began making distributions to eligible
early investors in December 2007 and to all investors in October 2008.





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.




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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.





6.   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 for the three and
six months ended June 30, 2009 were $0.4 million and $0.8 million, respectively.  For the three and six months ended June 30, 2008 management fees were $0.5 million and $1.0 million, respectively.





At times, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business.  At June 30, 2009 and December 31, 2008, there were no such amounts outstanding.





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





At June 30, 2009 and December 31, 2008, the carrying value of cash and cash equivalents, production receivable, salvage fund and accrued expenses approximate fair value.





8.   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, 2009, the Fund had committed to spend an additional $2.3 million related
to its investment 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 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 possible future legislation,
rule changes, or governmental or private claims.  At June 30, 2009 and December 31, 2008, 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 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 can reduce or eliminate insurance for the Fund.




11
 Table of Contents





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 based on current expectations and assumptions that are subject to risks and uncertainties that may cause actual results to differ materially from the forward-looking statements. These forward-looking statements generally are identified by the words “believe,” “project,” “expect,” “anticipate,” “estimate,”
“intend,” “strategy,” “plan,” “target,” “pursue,” “may,” “will likely result,” and similar expressions.  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, 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 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 disclosed in its 2008 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 natural 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 for distribution to its shareholders through the acquisition of “working interests” in the exploration, production and sale of oil and natural gas.





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.





Business Update





The Fund owns working interests and has participated in the drilling of sixteen wells, one is expected to commence drilling in the third quarter 2009, five have been determined to be successful, and ten have been determined to be dry holes, one of which was determined to be dry in 2009.




12
 Table of Contents





Future Projects


Raven Project


In June 2009, the Fund acquired a 6.25% working interest in the Raven Project, an exploratory well.   The Raven Project is expected to begin drilling in August 2009 and results are expected during the fourth quarter 2009.  Through June 30, 2009, the Fund has spent $23 thousand related to this well, for which the
total estimated budget is $1.4 million.





Successful Projects


Whistler Project


In July 2008, the Fund acquired an 11.0% working interest in the Whistler Project, a developmental well.   The Whistler Project was determined to be a commercial success in November 2008 and completion efforts are ongoing.  The well is expected to commence production during the first quarter 2010.   Through
June 30, 2009, the Fund has spent $1.9 million related to this well, for which the total estimated budget is $2.9 million.





Eugene Island 354


In May 2007, the Fund acquired a 33.0% working interest in the exploratory well Eugene Island 354.  In June 2007, the well was determined to be successful and production commenced in November 2007.  The Fund has spent $5.1 million related to this well.





Eugene Island 346/347


Well #1


In March 2007, the Fund acquired a 10.0% working interest in Eugene Island 346/347 well #1, an exploratory well.  The well began drilling in April 2007 and was determined to be successful in June 2007.  The well was completed and production commenced in June 2008.  The Fund has spent $7.1 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 well commenced drilling in May 2008.  In May 2008, Eugene Island 346/347 well #2 was determined to be commercially successful and production commenced in July 2008. The Fund has spent $1.5 million related to this well.





None of the Fund’s wells, including Eugene Island 346/347 wells #1 and #2 and Eugene Island 354, were materially damaged as a result of third quarter 2008 hurricane activity in the Gulf of Mexico.  However, the pipeline utilized to transport these wells’ oil and gas production has suffered severe damage thereby shutting
down production for these wells.   As a result, these wells have been shut-in while the pipeline repairs are completed by their owners.  There is no cost to the Fund related to these repair activities, however, these wells have not produced oil and gas or earned revenue during this repair period. The Eugene Island 354 well resumed production in June 2009 and the Eugene Island 346/347 wells are currently expected to resume production during the third quarter 2009.





West Cameron 593


In July 2006, the Fund acquired a 43.3% working interest in the exploratory well West Cameron 593.  West Cameron 593 was determined to be successful in September 2006 and production commenced in September 2007. The Fund has spent $13.1 million related to this well, of which the Fund has recorded impairments totaling $0.9 million
during the six months ended June 30, 2009.  During the third quarter 2008, the processing facility utilized to transport oil and gas for West Cameron 593 suffered hurricane damage, resulting in workover costs to the Fund totaling $0.6 million, of which $0.1 million were incurred during the six months ended June 30, 2009.





Dry Holes


South Timbalier 287


In November 2007, the Fund acquired a 4.0% working interest in the exploratory well South Timbalier 287.  This project began drilling in March 2008 and was determined to be an unsuccessful well, or dry hole, in January 2009.  Dry-hole costs related to this well totaled $4.3 million, of which $0.4 million were incurred
during the six months ended June 30, 2009.




13
 Table of Contents





Results of Operations





The following table summarizes the Fund’s results of operations for the three and six months ended June 30, 2009 and 2008 and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1. “Financial Statements” in Part I of this Quarterly Report.





Three months ended June 30,


Six months ended June 30,2009


2008


2009


2008(in thousands)RevenueOil and gas revenue

$
1,021


$
6,292


$
1,878


$
10,632ExpensesDepletion and amortization


1,239



2,482



2,437



4,576Impairment of proved properties


-



-



905



-Dry-hole costs


118



9,224



468



10,085Management fees to affiliate


422



512



849



1,028Operating expenses


404



225



605



545General and administrative expenses


103



221



229



405Total expenses


2,286



12,664



5,493



16,639Loss from operations


(1,265
)


(6,372
)


(3,615
)


(6,007
)Other incomeInterest income


12



108



30



367Net loss

$
(1,253
)

$
(6,264
)

$
(3,585
)

$
(5,640
)


Overview.During the three and six months ended June 30, 2009, the Fund had two producing wells, West Cameron 593, which came onto production in September 2007, and Eugene Island 354, which came back onto production in June 2009 after being shut-in due
to hurricane activity.  As previously discussed in the “Business Update”, Eugene Island 346/347 wells #1 and #2 are currently shut-in pending completion of pipeline repairs. There is no cost to the Fund relating to these repair activities, however, these wells have not produced oil and gas or earned revenue during this repair period. The Eugene Island 346/347 properties are currently expected to resume production during the third quarter 2009.





Oil and Gas Revenue.  Oil and gas revenue for the three months ended June 30, 2009 was $1.0 million, a $5.3 million decrease from the three months ended June 30, 2008.  The decrease is attributable to the impact of decreased sales volumes totaling
$3.6 million and decreased average prices totaling $1.6 million.




Oil sales volumes were 9 thousand barrels and 28 thousand barrels for the three months ended June 30, 2009 and 2008, respectively.  The Fund’s oil prices averaged $64 per barrel during the three months ended June 30, 2009 compared to $126 per barrel during the three months ended June 30, 2008.





Gas sales volumes were 121 thousand mcf and 232 thousand mcf for the three months ended June 30, 2009 and 2008, respectively.  The Fund’s gas prices averaged $3.71 per mcf during the three months ended June 30, 2009 compared to $11.39 per mcf during the three months ended June 30, 2008.





Oil and gas revenue for the six months ended June 30, 2009 was $1.9 million, an $8.8 million decrease from the six months ended June 30, 2008.  The decrease is attributable to the impact of decreased sales volumes totaling $6.1 million and decreased average prices totaling $2.6 million.





Oil sales volumes were 16 thousand barrels and 52 thousand barrels for the six months ended June 30, 2009 and 2008, respectively.  The Fund’s oil prices averaged $54 per barrel during the six months ended June 30, 2009 compared to $112 per barrel during the six months ended June 30, 2008.




14
 Table of Contents





Gas sales volumes were 246 thousand mcf and 452 thousand mcf for the six months ended June 30, 2009 and 2008, respectively.  The Fund’s gas prices averaged $4.07 per mcf during the six months ended June 30, 2009 compared to $10.68 per mcf during the six months ended June 30, 2008.





Oil and gas volumes were adversely impacted in both the three and six month periods ended June 30, 2009 as a result of hurricane repair activities related to the Eugene Island properties as discussed in “Overview” above.  Additionally, as West Cameron 593 is nearing the end of its productive life, its production rates
have declined to approximately 50% of its 2008 production.





Depletion and Amortization.Depletion and amortization for the three and six months ended June 30, 2009 was $1.2 million and $2.4 million, respectively, compared to $2.5 million and $4.6 million for the three and six months ended June 30, 2008.  The decreases
are attributable to decreased production volumes for West Cameron 593, Eugene Island 354 and Eugene Island 346/347 wells #1 and #2, as discussed above.  These decreases were partially offset by an increase in the West Cameron 593 depletion rate due to the revised reserve estimates provided by the Fund’s independent petroleum engineers at December 31, 2008.





Impairment of Proved Properties.  During the six months ended June 30, 2009, the Fund recorded an impairment to proved properties of $0.9 million, relating to West Cameron 593, due to lower oil and gas commodity prices.  There were no impairments
recorded during the three months ended June 30, 2009 and 2008 and the six months ended June 30, 2008.





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. During the three and six months ended June 30, 2009 and 2008, certain wells received credits from their respective operators upon review and audit of the wells’ costs.  The following table summarizes dry-hole costs inclusive of  credits.




Three months ended June 30,


Six months ended June 30,Lease Block

2009


2008


2009


2008(in thousands)South Timbalier 287

$
118


$
-


$
446


$
-High Island 38


-



6,407



19



6,407Mississippi Canyon 489/490


17



7



17



316Eugene Island 346/347 well #3


-



550



4



550West Cameron 109


-



-



-



599Walker Ridge 155


-



2,246



(4
)


2,246Other wells


(17
)


14



(14
)


(33
)$
118


$
9,224


$
468


$
10,085


Management Fees to Affiliate.Management fees for the three and six months ended June 30, 2009 were $0.4 million and $0.8 million, respectively, compared to $0.5 million and $1.0 million for the three and six months ended June 30, 2008.  An annual management
fee, totaling 2.5% of the 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 30,2009


2008


2009


2008(in thousands)Lease operating expense

$
284


$
215


$
477


$
530Workover costs


113



-



113



-Accretion expense


7



5



15



10Geological costs


-



5



-



5$
404


$
225


$
605


$
545


Lease operating expenses for the three and six months ended June 30, 2009 and 2008 were related to the West Cameron 593 and Eugene Island wells. Workover costs for the three and six months ended June 30, 2009 were related to the West Cameron 593 well.  There were no workover costs during the three and six months ended June 30,
2008.  Geological costs for the three and six months ended June 30, 2008 were related to Eugene Island 346/347 and South Timbalier 287.  There were no geological costs during the three and six months ended June 30, 2009.  Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.





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





15
 Table of Contents





Three months ended June 30,


Six months ended June 30,2009


2008


2009


2008(in thousands)Accounting fees

$
44


$
97


$
109


$
168Insurance expense


55



112



108



210Trust fees and other


4



12



12



27$
103


$
221


$
229


$
405





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 director’s 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 and six months ended June 30, 2009 was $12 thousand and $30 thousand, respectively, a decrease of $0.1 million and $0.3 million, respectively, from the three and six months ended June 30, 2008.  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.





Capital Resources and Liquidity





Operating Cash Flows


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





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





Investing Cash Flows


Cash flows used in investing activities for the six months ended June 30, 2009 were $2.5 million, principally related to capital expenditures for oil and gas properties totaling $2.4 million, inclusive of advances.  Additionally, the Fund increased its salvage fund investments by $13 thousand, which consisted of the interest earned
on this account.





Cash flows provided by investing activities for the six months ended June 30, 2008 were $2.4 million, principally 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 of $7.4 million,
inclusive of advances.  Additionally, the Fund increased its salvage fund investments by $15 thousand, which consisted of the interest earned on this account.





Financing Cash Flows


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





Cash flows used in financing activities for the six months ended June 30, 2008 were $7.2 million related to distributions paid.





Estimated Capital Expenditures





The Fund has entered into multiple 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, 2009, the Fund had committed to spend an additional
$2.3 million related to its investment properties.




16
 Table of Contents





When the Manager makes a decision to participate 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 an 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.





Capital expenditures for investment properties are funded with the capital raised by the Fund in its private placement offering, which is more than likely, all the capital it will be able to obtain. The number of projects in which the Fund can invest will naturally be limited, and each unsuccessful project the Fund experiences will reduce
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 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 are funded from cash flow from operations, as defined in the Fund’s limited liability company agreement, and the frequency and amount are within the Manager’s discretion subject to available cash from operations, reserve requirements and the Fund’s operations.





Off-Balance Sheet Arrangements





The Fund had no off-balance sheet arrangements as of June 30, 2009 and December 31, 2008 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 negotiate any such contracts.  No contractual obligations exist at June 30, 2009 and
December 31, 2008 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.





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, the Fund’s Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of June 30, 2009.




17
 Table of Contents





There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended June 30, 2009 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





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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS





None.





ITEM 5. OTHER INFORMATION





None.





ITEM 6. EXHIBITS





EXHIBITNUMBER
TITLE OF EXHIBIT

METHOD OF FILING31.1
Certification of Robert E. Swanson, Chief Executive Officer, pursuant to Securities Exchange Act Rule 13a-14(a).
Filed herewith31.2
Certification of Kathleen P. McSherry, Chief Financial Officer, pursuant to Securities Exchange Act Rule 13a-14(a).
Filed herewith32
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
 
 18
 Table of Contents





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, LLCDated:
July 30, 2009
By:
/s/

ROBERT E. SWANSONName:

Robert E. SwansonTitle:

Chief Executive Officer(Principal Executive Officer)Dated:
July 30, 2009
By:
/s/

KATHLEEN P. MCSHERRYName:

Kathleen P. McSherryTitle:

Executive Vice President and Chief Financial Officer(Principal Financial Officer)