UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

x
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended JuneSeptember 30, 2011

or

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _______________________to____________________________
 
Commission File No:  000-53591

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

Delaware
(State or other jurisdiction of
incorporation or organization)
 
26-0870318
(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  xý 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 xý      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 fileroAccelerated filero
Non-accelerated filer
(Do not check if a smaller reporting company)
o
Smaller reporting company
 
xý
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).       Yes  o  No  xý
 
As of July 28,November 1, 2011 the Fund had 477.8874 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 JuneSeptember 30, 2011 and December 31, 2010
1
  
Unaudited Condensed Statements of Operations for the three and sixnine months ended
JuneSeptember 30, 2011 and 2010
2
  
Unaudited Condensed Statements of Cash Flows for the sixnine months ended
JuneSeptember 30, 2011 and 2010
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
15
Item 4.
Controls and Procedures
15
  
PART II - OTHER INFORMATION 
Item 1.
Legal Proceedings
15
Item 1A.
Risk Factors
15
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds
15
Item 3.
Defaults Upon Senior Securities
15
Item 4.
(Removed and Reserved)
15
Item 5.
Other Information
15
Item 6.
Exhibits
16
   
 
SIGNATURES
1617
 
 
 
 
 
 
 
PART I - FINANCIAL INFORMATION
PART I - FINANCIAL INFORMATION 
       

ITEM 1.  FINANCIAL STATEMENTS

RIDGEWOOD ENERGY X FUND, LLC
UNAUDITED CONDENSED BALANCE SHEETS
(in thousands, except share data)
June 30,December 31,
20112010
ASSETS
Current assets:
Cash and cash equivalents$10,791$6,694
Short-term investments in marketable securities9,00212,993
Production receivable1,333985
Receivable from sale of oil and gas properties-2,330
Other current assets27530
Total current assets21,40123,032
Salvage fund1,1311,117
Oil and gas properties:
Advances to operators for working interests and expenditures-452
Unproved properties345334
Proved properties19,84418,772
Less: accumulated depletion and amortization(7,821)(5,522)
Total oil and gas properties, net12,36814,036
Total assets$34,900$38,185
LIABILITIES AND MEMBERS' CAPITAL
Current liabilities:
Due to operators$758$266
Accrued expenses7247
Total current liabilities830313
Asset retirement obligations458458
Total liabilities1,288771
Commitments and contingencies (Note 9)
Members' capital:
Manager:
Distributions(1,358)(733)
Retained earnings (accumulated deficit)490(209)
Manager's total(868)(942)
Shareholders:
Capital contributions (500 shares authorized;
477.8874 issued and outstanding)94,69894,698
Syndication costs(11,080)(11,080)
Distributions(9,869)(4,156)
Accumulated deficit(39,269)(41,106)
Shareholders' total34,48038,356
Total members' capital33,61237,414
Total liabilities and members' capital$34,900$38,185
  September 30, 2011  December 31, 2010 
ASSETS      
Current assets:      
Cash and cash equivalents $8,624  $6,694 
Short-term investments in marketable securities  12,002   12,993 
Production receivable  1,304   985 
Receivable from sale of oil and gas properties  -   2,330 
Other current assets  369   30 
Total current assets  22,299   23,032 
Salvage fund  1,138   1,117 
Oil and gas properties:        
Advances to operators for working interests and expenditures  3   452 
Unproved properties  347   334 
Proved properties  20,104   18,772 
Less:  accumulated depletion and amortization  (10,584)  (5,522)
Total oil and gas properties, net  9,870   14,036 
Total assets $33,307  $38,185 
         
LIABILITIES AND MEMBERS' CAPITAL        
Current liabilities:        
Due to operators $832  $266 
Accrued expenses  26   47 
Total current liabilities  858   313 
Asset retirement obligations  458   458 
Total liabilities  1,316   771 
Commitments and contingencies (Note 6)        
Members' capital:        
Manager:        
Distributions  (1,748)  (733)
Retained earnings (accumulated deficit)  1,025   (209)
Manager's total  (723)  (942)
Shareholders:        
Capital contributions (500 shares authorized;        
477.8874 issued and outstanding)  94,698   94,698 
Syndication costs  (11,080)  (11,080)
Distributions  (12,081)  (4,156)
Accumulated deficit  (38,823)  (41,106)
Shareholders' total  32,714   38,356 
Total members' capital  31,991   37,414 
Total liabilities and members' capital $33,307  $38,185 
The accompanying notes are an integral part of these unaudited condensed financial statements.
1
RIDGEWOOD ENERGY X FUND, LLC
 
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS 
(in thousands, except per share data) 
             
  Three months ended June 30,  Six months ended June 30, 
  2011  2010  2011  2010 
Revenue            
Oil and gas revenue $3,598  $813  $6,276  $1,689 
                 
Expenses                
Depletion and amortization  1,539   125   2,299   429 
Dry-hole costs  (109)  5,701   (41)  5,868 
Management fees to affiliate (Note 7)  361   438   723   878 
Operating expenses  275   12   524   69 
General and administrative expenses  149   76   204   190 
Total expenses  2,215   6,352   3,709   7,434 
Income (loss) from operations  1,383   (5,539)  2,567   (5,745)
Other (loss) income  (44)  12   (31)  27 
Net income (loss) $1,339  $(5,527) $2,536  $(5,718)
                 
Manager Interest                
Net income (loss) $404  $(17) $699  $20 
                 
Shareholder Interest                
Net income (loss) $935  $(5,510) $1,837  $(5,738)
Net income (loss) per share $1,957  $(11,530) $3,844  $(12,007)
                 
                 
                 
The accompanying notes are an integral part of these unaudited condensed financial statements. 
RIDGEWOOD ENERGY X FUND, LLC
 
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS 
(in thousands) 
       
  Six months ended June 30, 
  2011  2010 
       
Cash flows from operating activities      
Net income (loss) $2,536  $(5,718)
Adjustments to reconcile net income (loss) to net cash        
   provided by operating activities:        
Depletion and amortization  2,299   429 
Dry-hole costs  (41)  5,868 
Derivative instrument loss  53   - 
Changes in assets and liabilities:        
Increase in production receivable  (348)  (57)
(Increase) decrease in other current assets  (181)  3 
Increase (decrease) in due to operator  107   (30)
Increase (decrease) in accrued expenses  25   (172)
Net cash provided by operating activities  4,450   323 
         
Cash flows from investing activities        
Payments to operators for working interests and expenditures  -   (108)
Capital expenditures for oil and gas properties  (330)  (5,317)
Proceeds from the sale of oil and gas properties  2,330   - 
Investments in marketable securities  (9,001)  (13,001)
Proceeds from the maturity of marketable securities  13,000   25,031 
Interest reinvested in salvage fund  (14)  (14)
Net cash provided by investing activities  5,985   6,591 
         
Cash flows from financing activities        
Distributions  (6,338)  (878)
Net cash used in financing activities  (6,338)  (878)
         
Net increase in cash and cash equivalents  4,097   6,036 
Cash and cash equivalents, beginning of period  6,694   3,248 
Cash and cash equivalents, end of period $10,791  $9,284 
         
Supplemental schedule of non-cash investing activities        
Advances used for capital expenditures in oil and gas properties
reclassified to proved properties and dry-hole costs		 $452  $2,907 
         
         
The accompanying notes are an integral part of these unaudited condensed financial statements. 
RIDGEWOOD ENERGY X FUND, LLC
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

1.   Organization and Purpose
The Ridgewood Energy X Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 30, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 2, 2008 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 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, 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.  These unaudited interim condensed financial statements should be read in conjunction with the Fund’s December 31, 2010 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, which, for interest bearing deposits, are $250 thousand per insured financial institution.  Additionally, non-interest bearing deposits are fully insured through December 31, 2012, after which they will be included within the $250 thousand limit.  At June 30, 2011, the Fund’s bank balances exceeded federally insured limits by $9.3 million, all of which 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 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, 2011, the Fund had two short-term, held-to-maturity investments of $4.0 million and $5.0 million, which mature in October 2011 and December 2011, respectively.

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, 2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity, of $1.0 million, which mature in August 2013.  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 as dry-hole costs.  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.
Capitalized acquisition costs of producing oil and gas properties are depleted by the units-of-production method.
At June 30, 2011 and December 31, 2010, amounts recorded in due to operators totaling $0.5 million and $0.2 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 or proved 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.

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.
5
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.  Derivative instruments 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 other 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 a permanent impairment in value has occurred.  The fair value determinations require considerable judgment and are sensitive to change.  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.

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 beginning January 1, 2010.  The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, which will be effective for the Fund’s financial statements for the year ending December 31, 2011. The adoption of the guidance is not expected to have a material impact.
1
RIDGEWOOD ENERGY X FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
  Three months ended September 30,  Nine months ended September 30, 
  2011  2010  2011  2010 
Revenue            
Oil and gas revenue $4,447  $2,162  $10,723  $3,851 
                 
Expenses                
Depletion and amortization  2,763   562   5,062   991 
Dry-hole costs  7   128   (34)  5,996 
Management fees to affiliate (Note 4)  362   402   1,085   1,280 
Operating expenses  399   171   923   240 
General and administrative expenses  45   134   249   324 
Total expenses  3,576   1,397   7,285   8,831 
Income (loss) from operations  871   765   3,438   (4,980)
Other income  110   15   79   42 
Net income (loss) $981  $780  $3,517  $(4,938)
                 
Manager Interest                
Net income $535  $215  $1,234  $235 
                 
Shareholder Interest                
Net income (loss) $446  $565  $2,283  $(5,173)
Net income (loss) per share $933  $1,182  $4,777  $(10,825)
The accompanying notes are an integral part of these unaudited condensed financial statements.
2
RIDGEWOOD ENERGY X FUND, LLC
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
  Nine months ended September 30, 
  2011  2010 
       
Cash flows from operating activities      
Net income (loss) $3,517  $(4,938)
Adjustments to reconcile net income (loss) to net cash        
   provided by operating activities:        
Depletion and amortization  5,062   991 
Dry-hole costs  (34)  5,996 
Derivative instrument income  (48)  - 
Derivative instrument settlements  2   - 
Changes in assets and liabilities:        
Increase in production receivable  (319)  (588)
Increase in other current assets  (302)  (44)
Increase (decrease) in due to operator  221   (18)
Decrease in accrued expenses  (21)  (201)
Net cash provided by operating activities  8,078   1,198 
         
Cash flows from investing activities        
Payments to operators for working interests and expenditures  (3)  (771)
Capital expenditures for oil and gas properties  (514)  (7,306)
Proceeds from the sale of oil and gas properties  2,330   - 
Investments in marketable securities  (12,000)  (13,001)
Proceeds from the maturity of marketable securities  13,000   29,035 
Interest reinvested in salvage fund  (21)  (21)
Net cash provided by investing activities  2,792   7,936 
         
Cash flows from financing activities        
Distributions  (8,940)  (1,522)
Net cash used in financing activities  (8,940)  (1,522)
         
Net increase in cash and cash equivalents  1,930   7,612 
Cash and cash equivalents, beginning of period  6,694   3,248 
Cash and cash equivalents, end of period $8,624  $10,860 
         
Supplemental schedule of non-cash investing activities        
Advances used for capital expenditures in oil and gas properties reclassified to proved properties and dry-hole costs $452  $2,907 
The accompanying notes are an integral part of these unaudited condensed financial statements.
3
RIDGEWOOD ENERGY X FUND, LLC
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

1.   Organization and Summary of Significant Accounting Policies

Organization
The Ridgewood Energy X Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on August 30, 2007 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of January 2, 2008 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 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 4 and 6.
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, 2010 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, which, for interest bearing deposits, are $250 thousand per insured financial institution.  Additionally, non-interest bearing deposits are fully insured through December 31, 2012, after which they will be included within the $250 thousand limit.  At September 30, 2011, the Fund’s bank balances exceeded federally insured limits by $5.8 million, all of which was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

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 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 September 30, 2011, the Fund had three short-term, held-to-maturity investments of $4.0 million, $5.0 million and $3.0 million, which mature in October 2011, December 2011 and February 2012, respectively.
4
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 September 30, 2011, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity, of $1.0 million, which mature in August 2013.  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 as dry-hole costs.  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.
Capitalized acquisition costs of producing oil and gas properties are depleted by the units-of-production method.
At September 30, 2011 and December 31, 2010, amounts recorded in due to operators totaling $0.5 million and $0.2 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 or proved 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.

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.
5
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.  Derivative instruments 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 other 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 2.  “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 a permanent impairment in value has occurred.  The fair value determinations require considerable judgment and are sensitive to change.  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.

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.

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 $8 thousand to $16 thousand per share.  The Fund began making distributions to eligible early investors in December 2008 and to all investors in April 2011.

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.
 
 
6
 
4.   Derivative Instruments
The Fund periodically enters into derivative contracts relating to its oil or gas production.  During the second quarter 2011, the Fund entered into three twelve-month derivative contracts for put options relating to the pricing of oil for a portion of its anticipated production.  The use of such derivative instruments limits the downside risk of adverse price movements.  Currently, the Fund has elected not to use hedge accounting for its derivatives and consequently, the derivatives are marked-to-market each quarter with fair value gains and losses recognized as other income on the statement of operations.  The estimated fair value of these contracts is based upon various factors, including reported prices on the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  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.
Derivative instruments are carried at their fair value on the balance sheet within “Other current assets”.  The derivative contracts relating to oil pricing are settled based upon reported prices on ICE.  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 “Other (loss) income.”  Settlements of derivative contracts are reflected in operating activities on the statement of cash flows.
At June 30, 2011, the Fund had outstanding derivative contracts with respect to its future production of oil that are not designated for hedge accounting as detailed in the following table.
Production Period Type of Contract Volume in barrels ICE Contract
Price per barrel		 
Estimated
 Fair Value
 Asset
        (in thousands)
July 1, 2011 - April 30, 2012 Put Options  16,002 $105 $71
July 1, 2011 - April 30, 2012 Put Options  7,664 $112 $51
July 1, 2011 - April 30, 2012 Put Options  7,664 $100 $25
For the three and six months ended June 30, 2011, the Fund’s derivative instrument income consisted of realized losses of $38 thousand and unrealized losses of $15 thousand, respectively.  There was no derivative instrument income for the three and six months ended June 30, 2010.

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, 2011, the Fund had no unproved properties with capitalized exploratory well costs in excess of one year.

In December 2010, after determining not to proceed with the completion of the Aspen Project, the Fund entered into an agreement to sell its working interest in the Aspen Project to Stone Energy Corporation, for net proceeds of $2.3 million in cash, which resulted in a loss of $3.6 million.  The proceeds from the sale of the Aspen Project were collected in January 2011.

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 such credits, are detailed in the following table.
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   Three months ended June 30,  Six months ended June 30, 
Lease Block  2011  2010  2011  2010 
   (in thousands) 
Dakota Project  $(8) $3,464  $66  $3,464 
Targa Project   -   2,276   1   2,276 
Other wells   (101)  (39)  (108)  128 
   $(109) $5,701  $(41) $5,868 
6.   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 $8 thousand to $16 thousand per share.  The Fund began making distributions to eligible early investors in December 2008 and to all investors in April 2011.

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.

In January 2011, proceeds from the sale of the Aspen Project were distributed to the Manager and shareholders totaling $23 thousand and $2.3 million, respectively.

Recent Accounting Pronouncements
The Fund has considered recent accounting pronouncements and believes that these recent pronouncements will not have a material effect on the Fund’s financial statements.

2.   Derivative Instruments
The Fund periodically enters into derivative contracts relating to its oil or gas production.  During the second quarter 2011, the Fund entered into three twelve-month derivative contracts for put options relating to the pricing of oil for a portion of its anticipated production.  The use of such derivative instruments limits the downside risk of adverse price movements.  Currently, the Fund has elected not to use hedge accounting for its derivatives and consequently, the derivatives are marked-to-market each quarter with fair value gains and losses recognized as other income on the statement of operations.  The estimated fair value of these contracts is based upon various factors, including reported prices on the Intercontinental Exchange (“ICE”), volatility, and the time value of options.  See Note 5. “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.
Derivative instruments are carried at their fair value on the balance sheet within “Other current assets”.  The derivative contracts relating to oil pricing are settled based upon reported prices on ICE.  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 “Other income.”  Settlements of derivative contracts are reflected in operating activities on the statement of cash flows.
At September 30, 2011, the Fund had outstanding derivative contracts with respect to its future production of oil that are not designated for hedge accounting as detailed in the following table.

Production Period Type of Contract Volume in barrels  
ICE Contract
Price per barrel
  
Estimated
 Fair Value
 Asset
 
          (in thousands) 
October 1, 2011 - April 30, 2012 Put Options  10,507  $105  $120 
October 1, 2011 - April 30, 2012 Put Options  5,013  $112  $81 
October 1, 2011 - April 30, 2012 Put Options  5,013  $100  $44 

For the three months ended September 30, 2011, the Fund’s derivative instrument income consisted of realized losses of $53 thousand and unrealized gains of $0.2 million, respectively.  For the nine months ended September 30, 2011, the Fund’s derivative instrument income consisted of realized losses of $0.1 million and unrealized gains of $0.1 million, respectively.  There was no derivative instrument income for the three and nine months ended September 30, 2010.

3.   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 September 30, 2011, the Fund had no unproved properties with capitalized exploratory well costs in excess of one year.

In December 2010, after determining not to proceed with the completion of the Aspen Project, the Fund entered into an agreement to sell its working interest in the Aspen Project to Stone Energy Corporation, for net proceeds of $2.3 million in cash, which resulted in a loss of $3.6 million.  The proceeds from the sale of the Aspen Project were collected in January 2011.
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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 such credits, are detailed in the following table.

  Three months ended September 30,  Nine months ended September 30, 
Lease Block 2011  2010  2011  2010 
  (in thousands) 
Dakota Project $-  $-  $66  $3,464 
Targa Project  (1)  -   -   2,276 
Other wells  8   128   (100)  256 
  $7  $128  $(34) $5,996 
4.   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 each of the three months ended September 30, 2011 and 2010 were $0.4 million.   Management fees for the nine months ended September 30, 2011 and 2010 were $1.1 million and $1.3 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund.  Distributions paid to the Manager for the three months ended September 30, 2011 and 2010 were $0.4 million and $0.1 million, respectively. Distributions paid to the Manager for the nine months ended September 30, 2011 and 2010 were $1.0 million and $0.2 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.

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.

5.   Fair Value Measurements

At September 30, 2011 and December 31, 2010, cash and cash equivalents, short-term investments in marketable securities, production receivable, receivable from sale of oil and gas properties, salvage fund and accrued expenses approximate fair value.  At September 30, 2011, derivative instruments are recorded at fair value based on Level 2 inputs, as the instruments are over-the-counter derivatives with a third party.

6.   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 September 30, 2011, the Fund had committed to spend an additional $6.8 million related to its investment properties, of which $2.0 million is expected to be spent during the next twelve months.
8

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 September 30, 2011 and December 31, 2010, there were no known environmental contingencies that required the Fund to record a liability.

In response to the April 2010 oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore.  Such proposals could result in significant additional laws or regulations governing the Fund’s operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.

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.

Lease Expirations
On April 25, 2011, the Fund received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) that its extension request for the Diller Project lease, which was scheduled to expire on May 31, 2011, had been approved, extending such lease through October 31, 2011.  Additionally, in May 2011, the BOE issued a one-year extension for all leases that had been set to expire prior to December 15, 2011. Accordingly, the Diller and Marmalard leases have been extended through May 31, 2012.

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 for each of the three months ended June 30, 2011 and 2010 were $0.4 million.   Management fees for the six months ended June 30, 2011 and 2010 were $0.7 million and $0.9 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions made by the Fund.  Distributions paid to the Manager for the three months ended June 30, 2011 and 2010 were $0.3 million and $0.1 million, respectively. Distributions paid to the Manager for the six months ended June 30, 2011 and 2010 were $0.6 million and $0.1 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.

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, 2011 and December 31, 2010, cash and cash equivalents, short-term investments in marketable securities, production receivable, receivable from sale of oil and gas properties, salvage fund and accrued expenses approximate fair value.  At June 30, 2011, derivative instruments are recorded at fair value based on Level 2 inputs, as the instruments are over-the-counter derivatives with a third party.
8
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, 2011, the Fund had committed to spend an additional $7.9 million related to its investment properties, of which $3.5 million is expected to be spent 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 possible future legislation, rule changes, or governmental or private claims.  At June 30, 2011 and December 31, 2010, there were no known environmental contingencies that required the Fund to record a liability.

In response to the April 2010 oil spill in the Gulf of Mexico, the United States Congress is considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore.  Such proposals could result in significant additional laws or regulations governing the Fund’s operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions, which could have a material adverse effect on the Fund’s operating results and cash flows.

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.

Lease Expirations
On April 25, 2011, the Fund received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) that its extension request for the Diller Project lease, which was scheduled to expire on May 31, 2011, had been approved, extending such lease through October 31, 2011.  Additionally, in May 2011, the BOE issued a one-year extension for all leases that had been set to expire prior to December 15, 2011. Accordingly, the Diller and Marmalard leases have been extended through May 31, 2012.

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 X 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-looking 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 2010 Annual Report on Form 10-K.

Overview of the Fund’s Business

The Fund is a Delaware limited liability company formed on August 30, 2007 to primarily 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 shallow water or deepwater oil and natural gas projects.  However, the Fund is not required to make distributions to shareholders except as provided in the Fund’s limited liability company agreement (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 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.

 
10

Business Update
Information regarding the Fund’s current projects, all of which are located in the offshore waters of the Gulf of Mexico, is provided in the following table.

     Total Spent  Total      Total Spent  Total  
  Working  Through  Fund   Working  Through  Fund  
Lease BlockLease Block Interest  June 30, 2011  Budget Status Interest  September 30, 2011  Budget Status
     (in thousands)      (in thousands)  
Non-producing PropertiesNon-producing Properties                    
Diller Project  0.75% $160  $4,705 Acquired interest in May 2010.  Drilling date to be determined.  See further discussion below.
Marmalard Project  0.75% $185  $3,506 Acquired interest in May 2010.  Drilling date to be determined.  See further discussion below.
Diller Project  0.75%  $160  $2,990 Acquired interest in May 2010.  Drilling date expected in fourth quarter 2011, pending permit approval.  See further discussion below.
Marmalard Project  0.75%  $187  $4,112 Acquired interest in May 2010.  Drilling date to be determined.  See further discussion below.
Producing PropertiesProducing Properties                          
Carrera Project  5.0% $7,605  $7,605 Production commenced June 2011.
Liberty Project  5.0% $7,524  $7,524 Production commenced July 2010.
Main Pass 283/279 well # 1  14.0% $4,277  $4,277 Production commenced in 2008.
Carrera Project  5.0%  $7,862  $7,887 Well completed and production commenced June 2011.  Separator upgrade planned for fourth quarter 2011 at an estimated cost of $25 thousand.
Liberty Project  5.0%  $7,531  $7,531 Production commenced July 2010.
Main Pass 283/279 well # 1  14.0%  $4,277  $4,277 Production commenced in 2008. Well is currently shut-in due to water build up. Currently evaluating options for repair.
 
On April 25, 2011, the Fund received notification from the Bureau of Ocean Energy Management, Regulation and Enforcement (“BOE”) that its extension request for the Diller Project lease, which was scheduled to expire on May 31, 2011, had been approved, extending such lease through October 31, 2011.  Additionally, in May 2011, the BOE issued a one-year extension for all leases that had been set to expire prior to December 15, 2011.  Accordingly, the Diller and Marmalard leases have been extended through May 31, 2012.

Results of Operations

The following table summarizes the Fund’s results of operations for the three and sixnine months ended JuneSeptember 30, 2011 and 2010, 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,  Three months ended September 30,  Nine months ended September 30, 
 2011  2010  2011  2010  2011  2010  2011  2010 
 (in thousands)  (in thousands) 
Revenue                        
Oil and gas revenue $3,598  $813  $6,276  $1,689  $4,447  $2,162  $10,723  $3,851 
                                
Expenses                                
Depletion and amortization  1,539   125   2,299   429   2,763   562   5,062   991 
Dry-hole costs  (109)  5,701   (41)  5,868   7   128   (34)  5,996 
Management fees to affiliate  361   438   723   878   362   402   1,085   1,280 
Operating expenses  275   12   524   69   399   171   923   240 
General and administrative expenses  149   76   204   190   45   134   249   324 
Total expenses  2,215   6,352   3,709   7,434   3,576   1,397   7,285   8,831 
Income (loss) from operations  1,383   (5,539)  2,567   (5,745)  871   765   3,438   (4,980)
Other (loss) income  (44)  12   (31)  27 
Other income  110   15   79   42 
Net income (loss) $1,339  $(5,527) $2,536  $(5,718) $981  $780  $3,517  $(4,938)

Overview.  During the six months ended June 30, 2011, the Fund had three wells that produced for a total of 380 days, compared to one well that produced for a total of 181 days during the six months ended June 30, 2010.  The increase in total production days resulted from the onset of production for the Carrera and Liberty projects, which commenced in June 2011 and July 2010, respectively.  During the six months ended June 30, 2011, the Fund’s wells’ production rate averaged 1,517 mcfe/producing day, compared to 1,446 mcfe/producing day during the six months ended June 30, 2010.  The increase resulted from the onset of production for the Carrera and Liberty projects.
 
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Overview.   The following table provides information related to the Fund’s oil and gas production during the three and nine months ended September 30, 2011 and 2010.

  Three months ended September 30,  Nine months ended September 30, 
  2011  2010  2011  2010 
Number of wells producing  3   2   3   2 
Total number of production days  236   169   616   350 
Average mcfe per production day  1,540   1,657   1,541   1,548 

The increases in production days were related to the onset of production for the Liberty and Carrera projects, which commenced in July 2010 and June 2011, respectively.  The decreases in average mcfe per production day were primarily the result of the composite of the Fund’s productive wells.

Oil and Gas Revenue.   Oil and gas revenue for the three months ended JuneSeptember 30, 2011 was $3.6$4.4 million, a $2.8$2.3 million increase from the three months ended JuneSeptember 30, 2010.  The increase is primarily attributable to the impact of the change in average prices totaling $1.7$1.2 million, coupled with increased sales volume totaling $1.0$1.1 million.

Oil sales volumes were 23 thousand barrels and 4 thousand barrels for the three months ended June 30, 2011 and 2010, respectively.  The Fund’s oil prices averaged $112 per barrel during the three months ended June 30, 2011 compared to $76 per barrel during the three months ended June 30, 2010.

Gas sales volumes were 110 thousand mcf and 78 thousand mcf for the three months ended June 30, 2011 and 2010, respectively.  The Fund’s gas prices averaged $4.62 per mcf during the three months ended June 30, 2011 compared to $4.30 per mcf during the three months ended June 30, 2010.

Oil and gas revenue for the sixnine months ended JuneSeptember 30, 2011 was $6.3$10.7 million, a $4.6$6.9 million increase from the sixnine months ended JuneSeptember 30, 2010.  The increase is primarily attributable to increased sales volume totaling $4.3 million, coupled with the impact of the change in average oil prices totaling $2.6 million coupled with increased sales volume totaling $2.0$2.5 million.

Oil sales volumes were 44 thousand barrelsThe following table provides information related to the Fund’s oil and 8 thousand barrels forgas revenue during the sixthree and nine months ended JuneSeptember 30, 2011 and 2010, respectively.  The Fund’s oil prices averaged $105 per barrel during the six months ended June 30, 2011 compared to $76 per barrel during the six months ended June 30, 2010.
  Three months ended September 30,  Nine months ended September 30, 
  2011  2010  2011  2010 
Oil sales in thousands of barrels  35   19   79   28 
Average oil price per barrel $104  $74  $104  $75 
Gas sales in thousands of mcfs  107   105   336   266 
Average gas price per mcf $4.41  $4.55  $4.16  $4.58 

Gas sales volumes were 222 thousand mcf and 156 thousand mcf for the six months ended June 30, 2011 and 2010, respectively.  The Fund’s gas prices averaged $4.28 per mcf during the six months ended June 30, 2011 compared to $4.75 per mcf during the six months ended June 30, 2010.

The increases in sales volumes were primarily related to the timing of the onset of production for the Fund’s producing wells, as discussed in “Overview” above.

Depletion and Amortization. Depletion and amortization for the three and sixnine months ended JuneSeptember 30, 2011 was $1.5$2.8 million and $2.3$5.1 million, respectively, an increase of $1.4$2.2 million and $1.9$4.1 million from the three and sixnine months ended JuneSeptember 30, 2010, respectively.  The increase in the three month period resulted from an increase in average depletion rates totaling $1.2$2.0 million coupled with an increase in production volumes totaling $0.2 million.  The increase in the sixnine month period resulted from an increase in average depletion rates totaling $1.4$3.3 million, coupled with an increase in production volumes totaling $0.5$0.8 million.  The increases in average depletion rates were primarily the result of the composite of productive wells, which included higher cost reserve additions.

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 September 30,  Nine months ended September 30, 
Lease Block 2011  2010  2011  2010 
  (in thousands) 
Dakota Project $-  $-  $66  $3,464 
Targa Project  (1)  -   -   2,276 
Other wells  8   128   (100)  256 
  $7  $128  $(34) $5,996 
   Three months ended June 30,  Six months ended June 30, 
Lease Block  2011  2010  2011  2010 
   (in thousands) 
Dakota Project  $(8) $3,464  $66  $3,464 
Targa Project   -   2,276   1   2,276 
Other wells   (101)  (39)  (108)  128 
   $(109) $5,701  $(41) $5,868 

 
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Management Fees to Affiliate.   Management fees for each of the three months ended JuneSeptember 30, 2011 and 2010 were $0.4 million.  Management fees for the sixnine months ended JuneSeptember 30, 2011 and 2010 were $0.7$1.1 million and $0.9$1.3 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.
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Operating Expenses.  Operating expenses represent costs specifically identifiable or allocable to the Fund’s wells, as detailed in the following table.

 Three months ended June 30,  Six months ended June 30,  Three months ended September 30,  Nine months ended September 30, 
 2011  2010  2011  2010  2011  2010  2011  2010 
 (in thousands)  (in thousands) 
Lease operating expense $252  $39  $500  $90  $396  $158  $896  $248 
Other expense  23   (27)  24   (21)  3   13   27   (8)
 $275  $12  $524  $69  $399  $171  $923  $240 

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”.  The average production cost was $0.86$1.09 per mcfe and $0.87$0.94 per mcfe during the three and sixnine months ended JuneSeptember 30, 2011, respectively, compared to $0.31$0.60 per mcfe and $0.35$0.47 per mcfe during the three and sixnine months ended JuneSeptember 30, 2010, respectively.

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, 
  2011  2010  2011  2010 
  (in thousands) 
Accounting fees $57  $45  $96  $83 
Insurance expense  85   19   92   82 
Trust fees and other  7   12   16   25 
  $149  $76  $204  $190 

Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund.  
  Three months ended September 30,  Nine months ended September 30, 
  2011  2010  2011  2010 
  (in thousands) 
Insurance expense $31  $71  $123  $153 
Accounting fees  7   54   103   137 
Trust fees and other  7   9   23   34 
  $45  $134  $249  $324 

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.  Accounting fees represent audit and tax preparation fees, quarterly reviews and filing fees incurred by the Fund.  Trust fees represent bank fees associated with the management of the Fund’s cash accounts.
 
Other (Loss) Income.   Other (loss) income for the three and sixnine months ended JuneSeptember 30, 2011 and 2010 is detailed in the following table.

 Three months ended June 30,  Six months ended June 30,  Three months ended September 30,  Nine months ended September 30, 
 2011  2010  2011  2010  2011  2010  2011  2010 
 (in thousands)  (in thousands) 
Interest income $9  $12  $22  $27  $9  $15  $31  $42 
Realized losses on derivative instruments  (38)  -   (38)  -   (53)  -   (91)  - 
Unrealized losses on derivative instruments  (15)  -   (15)  - 
Unrealized gains on derivative instruments  154   -   139   - 
 $(44) $12  $(31) $27  $110  $15  $79  $42 

Capital Resources and Liquidity

Operating Cash Flows
Cash flows provided by operating activities for the sixnine months ended JuneSeptember 30, 2011 were $4.5$8.1 million, primarily related to revenue received of $5.9$10.4 million, partially offset by management fees of $0.7$1.1 million, operating expenses paid of $0.4$0.7 million, derivative purchases of $0.2 million and general and administrative expenses paid of $0.4 million and the purchase of derivative instruments of $0.2 million.
 
 
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Cash flows provided by operating activities for the sixnine months ended JuneSeptember 30, 2010 were $0.3$1.2 million, primarily related to revenue received of $1.6$3.3 million, partially offset by management fees of $0.9$1.3 million, general and administrative expenses paid of $0.2$0.6 million and operating expenses paid of $0.1 million and unfavorable working capital of $0.2$0.3 million.

Investing Cash Flows
Cash flows provided by investing activities for the sixnine months ended JuneSeptember 30, 2011 were $6.0$2.8 million, primarily related to proceeds from the maturity of U.S. Treasury securities of $13.0 million coupled with proceeds received from the sale of the Aspen Project of $2.3 million, partially offset by investments in U.S. Treasury securities of $9.0$12.0 million and capital expenditures for oil and gas properties of $0.3 million.$0.5 million, inclusive of advances.

Cash flows provided by investing activities for the sixnine months ended JuneSeptember 30, 2010 were $6.6$7.9 million, primarily related to proceeds from the maturity of U.S. Treasury securities of $25.0$29.0 million, partially offset by investments in U.S. Treasury securities of $13.0 million and capital expenditures for oil and gas properties of $5.4$8.1 million, inclusive of advances.

Financing Cash Flows
Cash flows used in financing activities for the sixnine months ended JuneSeptember 30, 2011 were $6.3$8.9 million, related to manager and shareholder distributions.

Cash flows used in financing activities for the sixnine months ended JuneSeptember 30, 2010 were $0.9$1.5 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 JuneSeptember 30, 2011, the Fund had committed to spend an additional $7.9$6.8 million related to its investment properties, of which $3.5$2.0 million is expected to be spent 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 by the Manager 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 is limited, and each unsuccessful project the Fund experiences exhausts its capital and reduces its ability to generate revenue.

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, if any, 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.

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 JuneSeptember 30, 2011 and December 31, 2010 and does not anticipate the use of such arrangements in the future.

 
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Contractual Obligations

The Fund enters into participation and joint 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 JuneSeptember 30, 2011 and December 31, 2010 other than those discussed in “Estimated Capital Expenditures” above.
 
Recent Accounting Pronouncements
 
See Note 31 of Notes to Unaudited Condensed Financial Statements – “Recent“Organization and Summary of Significant Accounting Standards”Policies” 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 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 JuneSeptember 30, 2011.

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended JuneSeptember 30, 2011 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

None.

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.
 
 
15
 
ITEM 6.  EXHIBITS

 
EXHIBIT
NUMBER
NUMBER      TITLE OF EXHIBIT METHOD OF FILING
    
3.2Amended Limited Liability Company Agreement between Ridgewood Energy Corporation and Investors of Ridgewood Energy X Fund, LLC dated April 13, 2011 Incorporated by reference to the Fund’s Form 10Q filed on May 3, 2011
    
31.1Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) Filed herewith
    
31.2Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a) Filed herewith
    
32Certifications 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, Executive Vice President and Chief Financial Officer of the Fund. Filed herewith
101.INSXBRL Instance Document *
    
101.SCHXBRL Taxonomy Extension Schema *
    
101.CALXBRL Taxonomy Extension Calculation Linkbase *
    
101.LABXBRL Taxonomy Extension Label Linkbase *
    
101.PREXBRL Taxonomy Extension Presentation Linkbase *
 
* Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Act of 1934 and otherwise are not subject to liability.
16
 
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 X FUND, LLC
Dated:July 28,November 1, 2011By:/s/  ROBERT E. SWANSON
   Name:  Robert E. Swanson
   Title:  Chief Executive Officer
      (Principal Executive Officer)
       
       
Dated:July 28,November 1, 2011By:/s/  KATHLEEN P. MCSHERRY
   Name:  Kathleen P. McSherry
   Title:  Executive Vice President and Chief Financial Officer
      (Principal Financial Officer)
 
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