g72513010q.htm

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

RIDGEWOOD ENERGY X FUND, LLC

UNAUDITED CONDENSED BALANCE SHEETS

(in thousands, except share data)

	June 30, 2013			December 31, 2012
Assets
Current assets:
Cash and cash equivalents	$	17,476		$	14,188
Short-term investments in marketable securities		-			5,000
Salvage fund		140			51
Production receivable		592			1,144
Other current assets		4			157
Total current assets		18,212			20,540
Salvage fund		1,046			1,122
Other assets		89			89
Oil and gas properties:
Advances to operators for working interests and expenditures		21			-
Proved properties		18,848			17,922
Equipment and facilities – in progress		139			61
Less: accumulated depletion, depreciation and amortization		(12,330	)		(11,493	)
Total oil and gas properties, net		6,678			6,490
Total assets	$	26,025		$	28,241

Liabilities And Members' Capital
Current liabilities:
Due to operators	$	1,478		$	363
Accrued expenses		48			40
Asset retirement obligations		140			51
Total current liabilities		1,666			454
Asset retirement obligations		784			720
Total liabilities		2,450			1,174

Commitments and contingencies (Note 5)

Members' capital:
Manager:
Distributions		(4,259	)		(3,695	)
Retained earnings		3,429			2,979
Manager's total		(830	)		(716	)

Shareholders:
Capital contributions (500 shares authorized;
477.8874 issued and outstanding)		94,698			94,698
Syndication costs		(11,080	)		(11,080	)
Distributions		(26,307	)		(23,109	)
Accumulated deficit		(32,906	)		(32,726	)
Shareholders' total		24,405			27,783
Total members' capital		23,575			27,067
Total liabilities and members' capital	$	26,025		$	28,241

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

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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,
	2013			2012		2013			2012
Revenue
Oil and gas revenue	$	1,994		$	3,184	$	4,812		$	7,232

Expenses
Depletion, depreciation and amortization		359			1,105		926			2,245
Dry-hole costs		1,867			2		1,867			96
Management fees to affiliate (Note 4)		335			362		670			724
Operating expenses		355			408		830			779
General and administrative expenses		111			86		263			170
Total expenses		3,027			1,963		4,556			4,014
(Loss) income from operations		(1,033	)		1,221		256			3,218
Other income (loss)		7			8		14			(44	)
Net (loss) income	$	(1,026	)	$	1,229	$	270		$	3,174

Manager Interest
Net income	$	159		$	352	$	450		$	817

Shareholder Interest
Net (loss) income	$	(1,185	)	$	877	$	(180	)	$	2,357
Net (loss) income per share	$	(2,480	)	$	1,835	$	(377	)	$	4,933

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

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RIDGEWOOD ENERGY X FUND, LLC

UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS

(in thousands)

	Six months ended June 30,
	2013			2012

Cash flows from operating activities
Net income	$	270		$	3,174
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization		926			2,245
Dry-hole costs		1,867			96
Derivative instrument loss		-			59
Derivative instrument settlements		-			6
Changes in assets and liabilities:
Decrease in production receivable		552			509
Decrease in other current assets		63			67
Increase (decrease) in due to operators		88			(12	)
Increase (decrease) in accrued expenses		8			(7	)
Net cash provided by operating activities		3,774			6,137

Cash flows from investing activities
Payments to operators for working interests
and expenditures		(21	)		-
Capital expenditures for oil and gas properties		(1,692	)		(1,216	)
Investments in marketable securities		-			(11,500	)
Proceeds from maturity of investments		5,002			5,500
Interest reinvested in salvage fund		(13	)		(14	)
Net cash provided by (used in) investing activities		3,276			(7,230	)

Cash flows from financing activities
Distributions		(3,762	)		(6,030	)
Net cash used in financing activities		(3,762	)		(6,030	)

Net increase (decrease) in cash and cash equivalents		3,288			(7,123	)
Cash and cash equivalents, beginning of period		14,188			14,687
Cash and cash equivalents, end of period	$	17,476		$	7,564

Supplemental schedule of non-cash investing activities
Advances used for capital expenditures in oil and gas properties reclassified to unproved properties	$	-		$	235

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

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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, which addresses matters such as the authority and voting rights of the Manager and shareholders, capitalization, transferability of membership interests, participation in costs and revenues, distribution of assets and dissolution and winding up. The Fund was organized 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.

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 5.

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, 2012 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.

Fair Value Measurements

The fair value measurement guidance provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consists of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority. Cash and cash equivalents and held-to-maturity investments approximate fair value based on Level 1 inputs.

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 are $250 thousand per insured financial institution. At June 30, 2013, the Fund’s bank balances exceeded federally insured limits by $7.5 million, of which $3.2 million was invested in money market accounts that invest solely in U.S. Treasury bills and notes.

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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 December 31, 2012, the Fund had investments in marketable securities that were classified as held-to-maturity, which matured in June 2013. 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 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, 2013 and December 31, 2012, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity of $0.9 million and $1.1 million, respectively. The held-to-maturity investments at June 30, 2013 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.

Exploration, development and acquisition costs are accounted for using the successful efforts method. Costs of acquiring unproved and proved oil and natural gas leasehold acreage, including lease bonuses, brokers’ fees and other related costs are capitalized. Costs of drilling and equipping productive wells and related production facilities are capitalized. Costs of developing production facilities and pipelines that service multiple oil and gas properties are segregated as “Equipment and facilities - in progress.” Exploratory costs are capitalized pending determination of whether proved reserves have been found. If proved commercial reserves are not found, exploratory drilling costs are expensed as dry-hole costs. Annual lease rentals and exploration expenses are expensed as incurred. All costs related to production activity and workover efforts are expensed as incurred.

Upon the sale, retirement or abandonment of a property, the cost and related accumulated depletion, depreciation and amortization, if any, is eliminated from the property accounts, and the resultant gain or loss is recognized.

At June 30, 2013 and December 31, 2012, amounts recorded in due to operators totaling $1.2 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. The following table presents changes in asset retirement obligations for the six months ended June 30, 2013 and for the year ended December 31, 2012.

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	June 30, 2013		December 31, 2012
	(in thousands)
Balance - Beginning of period	$	771	$	644
Liabilities incurred		64		141
Accretion expense		-		6
Revisions in estimated cash flows		89		(20	)
Balance - End of period	$	924	$	771

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 collectability 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 estimated fair value of such contracts is based upon various factors, including reported prices on the New York Mercantile Exchange (“NYMEX”) and the Intercontinental Exchange (“ICE”), volatility, and the time value of options. The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis on the statement of operations within other income or loss. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows. The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions. See Note 2. “Derivative Instruments”.

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 proved 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 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.

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Depletion, Depreciation and Amortization

Depletion, depreciation 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, development costs and related facilities. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs. In certain circumstances, equipment and facilities costs are depreciated over the estimated useful life of the asset.

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 to shareholders and the Manager in accordance with the LLC agreement.

Distributions

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

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

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. The use of such derivative instruments limits the downside risk of adverse price movements. The estimated fair value of such contracts is based upon various factors, including reported prices on NYMEX and ICE, volatility, and the time value of options. The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment.

The Fund had no derivative contracts during the three and six months ended June 30, 2013. For the three months ended June 30, 2012, the Fund’s derivative instrument income consisted of realized losses of $16 thousand and unrealized gains of $16 thousand. For the six months ended June 30, 2012, the Fund’s derivative instrument income consisted of realized losses of $59 thousand.

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.

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 adjustments to 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.

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	Three months ended June 30,					Six months ended June 30,
Project	2013			2012		2013			2012
	(in thousands)
Staurolite Project	$	1,876		$	-	$	1,876		$	-
Dakota Project		-			1		-			69
Other wells		(9	)		1		(9	)		27
	$	1,867		$	2	$	1,867		$	96

4. Related Parties

The LLC Agreement provides that the Manager render management, administrative and advisory services to the Fund. 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, 2013 were $0.3 million and $0.7 million, respectively. Management fees for the three and six months ended June 30, 2012 were $0.4 million and $0.7 million, respectively.

The Manager is entitled to receive a 15% interest in cash distributions from operations made by the Fund. Distributions paid to the Manager for the three and six months ended June 30, 2013 were $0.3 million and $0.6 million, respectively. Distributions paid to the Manager for the three and six months ended June 30, 2012 were $0.5 million and $0.9 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 amounts paid to the Manager have 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. Commitments and Contingencies

Capital Commitments

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 vary depending on the stage of development on a property-by-property basis. As of June 30, 2013, the Fund expects to spend $5.8 million related to its investments in oil and gas properties, of which $3.2 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, 2013 and December 31, 2012, there were no known environmental contingencies that required the Fund to record a liability.

Effective October 22, 2012, the United States Department of Interior, acting through the Bureau of Safety and Environmental Enforcement, implemented the Final Drilling Safety Rule (the “Final Rule”) which refined certain interim rules imposed in the immediate wake of the 2010 Deepwater Horizon oil spill. The Final Rule was promulgated for the prevention of waste and for the conservation of natural resources of the Outer Continental Shelf under the rulemaking authority of the Outer Continental Shelf Lands Act. The United States Congress continues to consider a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore, in addition to the Final Rule. 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 the Fund’s 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.

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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 a material 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.

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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 and production 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 projects, investments, insurance, capital expenditures and liquidity. 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 2012 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 natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. 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 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”).

Ridgewood Energy Corporation (the “Manager” or “Ridgewood Energy”) is the Manager, and as such, has direct and exclusive control over the management of the Fund’s operations. 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 effect on the Fund’s future profitability.

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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
		Working	through	Total Fund
Project		Interest	June 30, 2013	Budget	Status
			(in thousands)
Equipment and Facilities
	Delta House Project	0.06%	$ 139	$ 495	Floating production facility to service several wells, including the Diller and Marmalard wells. Expected to be placed in service in 2015.
Non-producing Properties
	Diller Project	0.88%	$ 1,351	$ 3,518	Well deemed to be a discovery in March 2012. Expected to commence production in 2015.
	Marmalard Project	0.88%	$ 1,615	$ 4,303	Marmalard well #1 deemed to be a discovery in May 2012 and is expected to commence production in 2015. Marmalard well #2 deemed to be a discovery in May 2013 and is expected to commence production in 2015.
Producing Properties
	Carrera Project	5.0%	$ 7,629	$ 8,214	Production commenced in 2011. Well was shut-in for several weeks due to a third-party pipeline issue during late-March/early April 2013. During second quarter 2013, the well's umbilical was flooded and electrical communication was lost. Costs to install a new umbilical are estimated to be $0.6 million. Compressor was installed in second quarter 2013 at a cost of $58 thousand.
	Liberty Project	5.0%	$ 7,520	$ 7,570	Production commenced in 2010. Well was shut-in for several weeks due to a third-party pipeline issue during late-March/early April 2013. Recompletion is planned for 2014 at an estimated cost of $50 thousand.
Fully Depleted Properties
	Main Pass 283/279 well # 1	14.0%	$ 4,219	$ 4,219	Production commenced in 2008. The Fund is in the process of withdrawing its interest in the project.
Dry Holes
	Staurolite Project	1.67%	$ 1,876	$ 1,876	Exploratory well, which began drilling in March 2013. Deemed to be a dry-hole in May 2013.

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Results of Operations

The following table summarizes the Fund’s results of operations for the three and six months ended June 30, 2013 and 2012, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1. “Financial Statements” in Part I in this Quarterly Report.

	Three months ended June 30,					Six months ended June 30,
	2013			2012		2013		2012
	(in thousands)
Revenue
Oil and gas revenue	$	1,994		$	3,184	$	4,812	$	7,232

Expenses
Depletion, depreciation and amortization		359			1,105		926		2,245
Dry-hole costs		1,867			2		1,867		96
Management fees to affiliate		335			362		670		724
Operating expenses		355			408		830		779
General and administrative expenses		111			86		263		170
Total expenses		3,027			1,963		4,556		4,014
(Loss) income from operations		(1,033	)		1,221		256		3,218
Other income (loss)		7			8		14		(44	)
Net (loss) income	$	(1,026	)	$	1,229	$	270	$	3,174

Overview. The following table provides information related to the Fund’s oil and gas production and oil and gas revenue during the three and six months ended June 30, 2013 and 2012.

	Three months ended June 30,				Six months ended June 30,
	2013		2012		2013		2012
Number of wells producing		2		2		2		3
Total number of production days		146		177		310		399
Oil sales (in thousands of barrels)		18		28		42		60
Average oil price per barrel	$	104	$	107	$	107	$	109
Gas sales (in thousands of mcfs)		36		46		103		124
Average gas price per mcf	$	4.82	$	2.42	$	4.26	$	2.23

The decreases in the number of production days and sales volumes during the three months ended June 30, 2013 were related to the Liberty and Carrera projects, which were shut-in for several weeks in late-March/early April 2013. The decreases in the number of production days and gas sales volume for the six months ended June 30, 2013 were attributable to Main Pass 283/279 well #1, which reached the end of its productive life in March 2012, coupled with the Liberty and Carrera projects. The decrease in oil sales volume during the six months ended June 30, 2013 was related to the Liberty and Carrera projects. See additional discussion in “Business Update” section above.

Oil and Gas Revenue. Oil and gas revenue for the three months ended June 30, 2013 was $2.0 million, a $1.2 million decrease from the three months ended June 30, 2012. The decrease is principally attributable to decreased sales volumes totaling $1.2 million. Oil and gas revenue for the six months ended June 30, 2013 was $4.8 million, a $2.4 million decrease from the six months ended June 30, 2012. The decrease is attributable to decreased sales volumes totaling $2.2 million coupled with the impact of the change in average prices totaling $0.1 million. See “Overview” above for additional information.

Depletion, Depreciation and Amortization. Depletion, depreciation and amortization for the three months ended June 30, 2013 was $0.4 million, a decrease of $0.7 million from the three months ended June 30, 2012. The decrease resulted from a decrease in production volumes totaling $0.4 million coupled with a decrease in average depletion rates totaling $0.3 million. Depletion, depreciation and amortization for the six months ended June 30, 2013 was $0.9 million, a decrease of $1.3 million from the six months ended June 30, 2012. The decrease resulted from a decrease in production volumes totaling $0.7 million coupled with a decrease in average depletion rates totaling $0.6 million. The decrease in average depletion rates was primarily attributable to revisions in reserve estimates, primarily related to the Carrera Project. See “Overview” above for additional information.

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Dry-hole Costs. Dry-hole costs are those costs incurred to drill and develop a well that is ultimately found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion of the well. At times, the Fund receives adjustments to 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,
Project	2013			2012		2013			2012
	(in thousands)
Staurolite Project	$	1,876		$	-	$	1,876		$	-
Dakota Project		-			1		-			69
Other wells		(9	)		1		(9	)		27
	$	1,867		$	2	$	1,867		$	96

Management Fees to Affiliate. Management fees for the three months ended June 30, 2013 and 2012 were $0.3 million and $0.4 million, respectively. Management fees for each of the six months ended June 30, 2013 and 2012 were $0.7 million. An annual management fee, totaling 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, is paid monthly to the Manager.

Operating Expenses. Operating expenses 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,
	2013		2012		2013		2012
	(in thousands)
Lease operating expense	$	264	$	314	$	604	$	656
Geological costs		16		94		134		95
Workover expense		75		-		92		28
	$	355	$	408	$	830	$	779

Lease operating expense relates to the Fund’s producing properties during each period as outlined above in “Overview”. The average production cost was $11.13 per barrel of oil equivalent (“BOE”) and $10.27 per BOE during the three and six months ended June 30, 2013, respectively, compared to $8.05 per BOE and $7.32 per BOE during the three and six months ended June 30, 2012, respectively. Geological costs, which represent costs incurred to obtain seismic data, surveys and lease rentals for the Fund’s projects, principally related to the Staurolite Project. Workover expense represents costs to restore or stimulate production of existing reserves of a proved property. During the three and six months ended June 30, 2013, workover expense related to the Liberty and Carrera Projects. During the six months ended June 30, 2012, workover expense related to Main Pass 283/279 well #1.

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,
	2013		2012		2013		2012
	(in thousands)
Insurance expense	$	66	$	30	$	182	$	84
Accounting and professional fees		40		51		66		73
Trust fees and other		5		5		15		13
	$	111	$	86	$	263	$	170

Insurance expense represents premiums related to producing well and control of well insurance, which varies depending upon the number of wells producing or drilling, and directors’ and officers’ liability insurance. Accounting and professional fees represent expenses for audits, quarterly reviews, tax preparation, reserve data engineering and reporting, and administration of filings. Trust fees represent bank fees associated with the management of the Fund’s cash accounts.

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Other Income (Loss). Other income (loss) for the three and six months ended June 30, 2013 and 2012 is detailed in the following table.

	Three months ended June 30,					Six months ended June 30,
	2013		2012			2013		2012
	(in thousands)
Interest income	$	7	$	8		$	14	$	15
Realized losses on derivative instruments		-		(16	)		-		(59	)
Unrealized gains on derivative instruments		-		16			-		-
	$	7	$	8		$	14	$	(44	)

Capital Resources and Liquidity

Operating Cash Flows

Cash flows provided by operating activities for the six months ended June 30, 2013 were $3.8 million, primarily related to revenue received of $5.4 million, partially offset by operating expenses paid of $0.7 million, management fees of $0.7 million and general and administrative expenses paid of $0.2 million.

Cash flows provided by operating activities for the six months ended June 30, 2012 were $6.1 million, primarily related to revenue received of $7.7 million, partially offset by operating expenses paid of $0.8 million, management fees of $0.7 million and general and administrative expenses paid of $0.1 million.

Investing Cash Flows

Cash flows provided by investing activities for the six months ended June 30, 2013 were $3.3 million, primarily related to proceeds received from the maturity of U.S. Treasury securities of $5.0 million, partially offset by capital expenditures for oil and gas properties of $1.7 million.

Cash flows used in investing activities for the six months ended June 30, 2012 were $7.2 million, primarily related to investments in U.S. Treasury securities of $11.5 million coupled with capital expenditures for oil and gas properties of $1.2 million, partially offset by proceeds received from the maturity of U.S. Treasury securities of $5.5 million.

Financing Cash Flows

Cash flows used in financing activities for the six months ended June 30, 2013 were $3.8 million, related to manager and shareholder distributions.

Cash flows used in financing activities for the six months ended June 30, 2012 were $6.0 million, related to manager and shareholder distributions.

Estimated Capital Expenditures

Capital expenditures for investment properties are funded with the capital raised by the Fund in its private placement offering, which may be 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 and capital expenditures for its investment properties. Operations are funded utilizing operating income, short-term investments, if any, existing cash on-hand and income earned therefrom.

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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. Due to the significant capital required to develop the Diller and Marmalard projects, distributions may be impacted by amounts reserved to provide for their ongoing development costs and funding their estimated asset retirement obligations.

Off-Balance Sheet Arrangements

The Fund had no off-balance sheet arrangements at June 30, 2013 and December 31, 2012 and does not anticipate the use of such arrangements in the future.

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 June 30, 2013 and December 31, 2012, other than those discussed in “Estimated Capital Expenditures” above.

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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Not required.

ITEM 4. CONTROLS AND PROCEDURES

In accordance with Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Fund’s management, including its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Fund’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Fund’s disclosure controls and procedures were effective as of June 30, 2013.

There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended June 30, 2013 that has materially affected, or is reasonably likely to materially affect, the Fund’s internal control over financial reporting.

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PART II – OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

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. MINE SAFETY DISCLOSURES

None.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

EXHIBIT NUMBER	TITLE OF EXHIBIT	METHOD OF FILING

31.1	Certification of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	Filed herewith

31.2	Certification of Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund, pursuant to Exchange Act Rule 13a-14(a)	Filed herewith

32	Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice President and Chief Financial Officer of the Fund	Filed herewith

101.INS	XBRL Instance Document	*

101.SCH	XBRL Taxonomy Extension Schema	*

101.CAL	XBRL Taxonomy Extension Calculation Linkbase	*

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document	*

101.LAB	XBRL Taxonomy Extension Label Linkbase	*

101.PRE	XBRL Taxonomy Extension Presentation Linkbase	*

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* 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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

				RIDGEWOOD ENERGY X FUND, LLC
Dated:	August 1, 2013	By:	/s/	ROBERT E. SWANSON
			Name:	Robert E. Swanson
			Title:	Chief Executive Officer
				(Principal Executive Officer)


Dated:	August 1, 2013	By:	/s/	KATHLEEN P. MCSHERRY
			Name:	Kathleen P. McSherry
			Title:	Executive Vice President and Chief Financial Officer
				(Principal Financial and Accounting Officer)

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

PART I - FINANCIAL INFORMATION			PAGE
Item 1.	Financial Statements		1
		Unaudited Condensed Balance Sheets as of June 30, 2013 and December 31, 2012	1
		Unaudited Condensed Statements of Operations for the three and six months ended June 30, 2013 and 2012	2
		Unaudited Condensed Statements of Cash Flows for the six months ended June 30, 2013 and 2012	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		16
Item 1A.	Risk Factors		16
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		16
Item 3.	Defaults Upon Senior Securities		16
Item 4.	Mine Safety Disclosures		16
Item 5.	Other Information		16
Item 6.	Exhibits		16
	SIGNATURES		17

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