| | | | | | | |
| | Year ended December 31, | |
| | 2007 | | 2006 | |
| |
| |
| |
|
Cash flows from operating activities | | | | | | | |
Net loss | | $ | (6,202 | ) | $ | (33,461 | ) |
Adjustments to reconcile net loss to net cash used in operating activities | | | | | | | |
Depletion and amortization | | | 701 | | | — | |
Dry-hole costs | | | 3,808 | | | 32,728 | |
Casualty loss | | | 3,193 | | | — | |
Accretion expense | | | 2 | | | — | |
Interest earned on marketable securities | | | (1,712 | ) | | (2,314 | ) |
Changes in assets and liabilities: | | | | | | | |
Increase in production receivable | | | (598 | ) | | — | |
Decrease (increase) in other current assets | | | 142 | | | (187 | ) |
Increase (decrease) in due to affiliates | | | 177 | | | (12 | ) |
Increase in accrued expenses payable | | | 72 | | | 28 | |
| |
|
| |
|
| |
Net cash used in operating activities | | | (417 | ) | | (3,218 | ) |
| |
|
| |
|
| |
|
Cash flows from investing activities | | | | | | | |
Payments to operators for working interests and expenditures | | | (1,866 | ) | | — | |
Capital expenditures for oil and gas properties | | | (16,025 | ) | | (23,149 | ) |
Salvage fund investments | | | (50 | ) | | (46 | ) |
Proceeds from insurance recovery | | | 13,908 | | | — | |
Proceeds from the sale of marketable securities | | | 51,613 | | | 116,000 | |
Investment in marketable securities | | | (65,318 | ) | | (65,001 | ) |
| |
|
| |
|
| |
Net cash (used in) provided by investing activities | | | (17,738 | ) | | 27,804 | |
| |
|
| |
|
| |
|
Cash flows from financing activities | | | | | | | |
Distributions | | | (487 | ) | | — | |
Syndication costs paid | | | — | | | (22 | ) |
| |
|
| |
|
| |
Net cash used in financing activities | | | (487 | ) | | (22 | ) |
| |
|
| |
|
| |
Net (decrease) increase in cash and cash equivalents | | | (18,642 | ) | | 24,564 | |
|
Cash and cash equivalents, beginning of period | | | 33,188 | | | 8,624 | |
| |
|
| |
|
| |
Cash and cash equivalents, end of period | | $ | 14,546 | | $ | 33,188 | |
| |
|
| |
|
| |
|
Supplemental schedule of non-cash investing activities | | | | | | | |
Advances used for capital expenditures in oil and gas properties reclassified to dry-hole costs and proved properties | | $ | — | | $ | 9,957 | |
| |
|
| |
|
| |
The accompanying notes are an integral part of these financial statements.
RIDGEWOOD ENERGY O FUND, LLC
NOTES TO FINANCIAL STATEMENTS
1. Organization and Purpose
The Ridgewood Energy O Fund, LLC (the “Fund”), a Delaware limited liability company, was formed on December 21, 2004 and operates pursuant to a limited liability company agreement (the “LLC Agreement”) dated as of February 16, 2005 by and among Ridgewood Energy Corporation (the “Manager”), and the shareholders of the Fund. Although the date of formation is December 21, 2004, the Fund did not begin business activities until February 16, 2005 when it began its private offering of shares of LLC member interest (the “Shares”). There were no business activities prior to February 16, 2005.
The Fund was organized to acquire, drill, construct and develop oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. The Fund has devoted most of its efforts to raising capital for oil and natural gas exploration activities. During 2007, the Fund began earning revenue and was determined to no longer be an exploratory stage enterprise.
The Manager performs (or arranges for the performance of) the management and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the contractual relations with outside custodians, depositories, accountants, attorneys, broker-dealers, corporate fiduciaries, insurers, banks and others as required. See Notes 2, 6 and 8.
2. Summary of Significant Accounting Policies
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to amounts advanced to and billed by operators, determination of proved reserves, impairment allowances 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 as cash and cash equivalents. At times, bank deposits may be in excess of federal insured limits. At December 31, 2007 and December 31, 2006, bank balances inclusive of the salvage fund exceeded federally insured limits by $14.4 million and $8.0 million, respectively. The Fund maintains bank deposits with accredited financial institutions to mitigate such risk.
Investments in Marketable Securities
At times the Fund may purchase short-term investments comprised of US Treasury Notes with maturities greater than three months that are considered held-to-maturity investments. Held-to-maturity securities are those investments that the Fund has the ability and intent to hold to maturity. Held-to-maturity investments are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximate fair value. Interest income is accrued as earned. At December 31, 2007, the Fund had held-to-maturity investments totaling $40.6 million, which matured in February 2008.
Salvage Fund
Pursuant to the Fund’s LLC Agreement, the Fund deposits in a separate interest-bearing account, or a salvage fund, money to provide for dismantling production platforms and facilities, plugging and abandoning the wells and removing the platforms, facilities and wells after their useful lives, in accordance with applicable federal and state laws and regulations.
Interest earned on the account will become part of the salvage fund. There are no legal restrictions on withdrawals from the salvage fund.
F-7
Oil and Natural Gas Properties
Investments in oil and natural gas properties are operated by unaffiliated entities (the “Operators”) 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 relating to the wells are advanced and billed by Operators through authorization for expenditures.
The successful efforts method of accounting for oil and gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and natural gas exploration costs, excluding the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves. If proved commercial reserves have not been found, exploratory drilling costs are expensed to dry-hole expense. Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of natural crude oil and natural gas, are capitalized. Expenditures for ongoing repairs and maintenance of producing properties are expensed as incurred.
Upon the sale or retirement of a proved property, the cost and related accumulated depletion and amortization will be eliminated from the property accounts, and the resultant gain or loss is recognized. On the sale or retirement of an unproved property, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed for impairment. The Manager does not currently intend to sell any of the Fund’s property interests.
Capitalized acquisition costs of producing oil and natural gas properties after recognizing estimated salvage values are depleted by the unit-of-production method.
As of December 31, 2007 and 2006 amounts recorded in due to operators totaling $2.0 million and $6.3 million, respectively, related to the acquisition of oil and gas property, both successful and unsuccessful, as well as recovery efforts. The 2007 balance was paid in the first quarter of 2008.
Advances to Operators for Working Interests and Expenditures
The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest. The Fund is required to advance its share of estimated cash outlay for the succeeding month’s operation. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are transferred to unproved properties.
Asset Retirement Obligations
For oil and natural 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.
| | | | | | | |
| | 2007 | | 2006 | |
| |
| |
| |
| | (in thousands) | |
Balance - January 1, | | $ | 37 | | $ | — | |
Liabilities incurred | | | 904 | | | 469 | |
Liabilities settled | | | (904 | ) | | (432 | ) |
Accretion expense | | | 2 | | | — | |
| |
|
| |
|
| |
Balance - December 31, | | $ | 39 | | $ | 37 | |
| |
|
| |
|
| |
Syndication Costs
Direct costs associated with offering the Fund’s shares including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and outside brokers are reflected as a reduction of shareholders’ capital.
Revenue Recognition and Production Receivable
Oil and natural gas sales are recognized and a production receivable is recorded when delivery is made by the Operator to the purchaser and title is transferred (i.e., production has been delivered to a pipeline or transport vehicle). The Fund began earning revenue in September 2007, with the onset of production for South Pelto 9. During 2006, the Fund had not earned revenue as there were no producing properties.
F-8
The volume of oil and natural gas sold on the Fund’s behalf may differ from the volume of oil and natural gas the Fund is entitled to. The Fund will account for such oil and natural gas production imbalances by the entitlements method. Under the entitlements method, the Fund will recognize a receivable from other working interest owners for volumes oversold by other working interest owners, and a payable to other working interest owners for volumes oversold by the Fund. As of December 31, 2007 and 2006, there were no material oil or natural gas balancing arrangements between the Fund and other working interest owners.
Impairment of Long-Lived Assets
In accordance with the provisions of SFAS No. 144, “Accounting for the Impairment of Long-Lived Assets”, long-lived assets, such as oil and natural gas properties, are evaluated when events or changes in circumstances indicate the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is made by comparing the carrying values of long-lived assets to the estimated future undiscounted cash flows attributable to the asset. The impairment loss recognized is the excess of the carrying value over the future discounted cash flows attributable to the asset or the estimated fair value of the asset. No impairments have been recorded in the Fund since inception.
Depletion and Amortization
Depletion and amortization of the cost of proved oil and natural gas properties are calculated using the units of production method. Proved developed reserves are used as the base for depleting the cost of successful exploratory drilling and development costs. The sum of proved developed and proved undeveloped reserves is used as the base for depleting (or amortizing) leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline costs. At December 31, 2006, the Fund did not have accumulated depletion as it had not had any production.
Income Taxes
No provision is made for income taxes in the financial statements. Because the Fund is a limited liability company, the income or losses are passed through and included in the tax returns of the individual shareholders.
Income and Expense Allocation
Profits and losses are to be allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for items of expense, loss, deduction and credit that are attributable to the expenditure of shareholders’ capital contributions, which are allocated 99% to shareholders and 1% to the Manager.
3. Recent Accounting Standards
In February 2007, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”), which permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. An entity would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The decision about whether to elect the fair value option is applied instrument by instrument, with a few exceptions; the decision is irrevocable; and it is applied only to entire instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets and liabilities in the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159 will not have a material impact on its financials. The Fund did not elect to measure existing assets and liabilities at fair value on the date of adoption.
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” (“SFAS No.157”), which applies under most other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 provides a common definition of fair value as the price that would be received to sell an asset or paid to transfer a liability in a transaction between market participants. The new standard also provides guidance on the methods used to measure fair value and requires expanded disclosures related to fair value measurements. SFAS No. 157 had originally been effective for financial statements issued for fiscal years beginning after November 15, 2007, however the FASB has agreed on a one year deferral for all nonfinancial assets and liabilities. The Fund believes this guidance will not have a material impact on the financial statements.
F-9
4. Unproved Properties - Capitalized Exploratory Well Costs
Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves. Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves. The following table reflects the net changes in unproved properties for the years ended December 31, 2007 and 2006. As of December 31, 2007 and 2006, the Fund had no capitalized exploratory well costs greater than one year.
| | | | | | | |
| | 2007 | | 2006 | |
| |
| |
| |
| | (in thousands) | |
Balance - January 1, | | $ | — | | $ | 16,873 | |
| | | | | | | |
Additions to capitalized exploratory well costs pending the determination of proved reserves | | | 7,647 | | | 3,879 | |
Reclassifications to proved properties based on the determination of proved reserves | | | (1,686 | ) | | (3,879 | ) |
Capitalized exploratory well costs charged to dry hole costs | | | | | | (16,873 | ) |
| |
|
| |
|
| |
Balance - December 31, | | $ | 5,961 | | $ | — | |
| |
|
| |
|
| |
Capitalization 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. Dry-hole costs are detailed in the table below.
| | | | | | | |
| | Year ended December 31, | |
| | 2007 | | 2006 | |
| |
| |
| |
| | (in thousands) | |
West Cameron 296 | | $ | 2,680 | | $ | — | |
West Delta 95 | | | 1,342 | | | 15,165 | |
West Cameron 78/95 | | | (52 | ) | | 4,395 | |
Eugene Island 357 | | | (14 | ) | | 4,120 | |
Eugene Island 334 | | | (148 | ) | | 9,048 | |
| |
|
| |
|
| |
| | $ | 3,808 | | $ | 32,728 | |
| |
|
| |
|
| |
5. Distributions
Distributions to shareholders are allocated in proportion to the number of shares held.
The Manager will determine whether available cash from operations, as defined in the Fund’s LLC Agreement, is to be distributed. Such distribution will be allocated 85% to the shareholders and 15% to the Manager, as defined in the Fund’s LLC Agreement.
Available cash from dispositions, as defined in the Fund’s LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of Available cash from dispositions will be distributed to shareholders and 15% to the Manager.
In December 2007, the Fund made its initial distributions to the Manager and shareholders totaling $0.1 million and $0.4 million, respectively. There were no distributions made by the Fund during the year ended December 31, 2006.
6. Related Parties
The LLC Agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager receives an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole costs incurred. Management fees of $2.3 million and $3.2 million were incurred for the years ended December 31, 2007 and 2006, respectively.
From time to time, short-term payables and receivables, which do not bear interest, arise from transactions with affiliates in the ordinary course of business. At December 31, 2007, the Fund owed affiliates $0.7 million related to insurance proceeds and revenue allocations. As of December 31, 2006, the Fund had a $16 thousand receivable, recorded in other current assets, related to insurance and the overpayment of fees from affiliates.
F-10
None of the compensation to be received by the Manager has been derived as a result of arm’s length negotiations.
The Fund has working interest ownership in certain projects to acquire and develop oil and natural gas projects with other entities that are likewise managed by the Manager.
7. Fair Value of Financial Instruments
At December 31, 2007 and 2006, the carrying value of cash and cash equivalents, short-term investments in marketable securities, salvage fund, production receivable and accrued expenses approximate fair value.
8. Commitments and Contingencies
Capital Commitments
The Fund has entered into multiple offshore operating agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of December 31, 2007, the Fund had committed to spend an additional $18.8 million relating to the properties.
Environmental Considerations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and the Operators are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and natural gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. At December 31, 2007 and 2006, there were no known environmental issues that required the Fund to record a liability.
Insurance Coverage
The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event which is not insured or not fully insured could have an adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the Manager’s investment programs. Claims made by other such programs can reduce or eliminate insurance for the Fund. The Fund records receivables for insured losses when the expected insurance proceeds are probable and reasonably estimable based upon assumptions and estimates derived from currently known facts.
West Delta 95
In 2005, the Fund acquired a 28.05% working interest in West Delta 95. In August 2005, before reaching its target depth, the project was evacuated in preparation for Hurricane Katrina. As a result of Hurricane Katrina, the well sustained damage. On April 15, 2006, recovery operations began, but were suspended in July 2006 as a result of the onset of hurricane season. Recovery operations totaling $12.9 million were completed and drilling resumed in January 2007. The Fund filed a claim with its insurance carrier for these recovery amounts and, in 2007, received $11.2 million as settlement of the claim. The Fund recorded casualty losses totaling $1.8 million related to the deductible, changes in estimates to, and the ultimate settlement of, this insurance claim. In February 2007, the well was determined to not have commercially productive quantities of either natural gas or oil and therefore was deemed to be a dry-hole.
West Cameron 78/95
In 2006, the Fund acquired a 30% working interest in West Cameron 78/95. The well began drilling on April 21, 2006. Drilling went according to plan until the drill string became stuck. The smaller drill pipe was recovered and the well was sidetracked, or re-drilled. Drilling continued until the well was determined to be a dry-hole. In July 2006 the decision was made to plug and abandon the well. During 2006, the Fund recorded a casualty loss of $0.2 million related to the insurance deductible for this claim. During 2007, the Fund recorded an additional casualty loss of $1.5 million as a result of changes in estimates to, and the ultimate settlement of, the insurance claim. The Fund received proceeds of $2.3 million for the settlement of this claim during the fourth quarter of 2007.
F-11
Supplemental Financial Information - Information about Oil and Natural Gas Producing Activities – Unaudited
In accordance with Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities,” this section provides supplemental information on oil and natural gas exploration and producing activities of the Fund. The Fund has one well classified as a proved property, South Pelto 9, which was deemed to have proved reserves in late-2006.
The Fund is engaged solely in oil and natural gas activities, all of which are located in the United States offshore waters of Texas and Louisiana in the Gulf of Mexico.
Table I - Capitalized Costs Related to Oil and Natural Gas Exploration and Producing Activities
| | | | | | | |
| | December 31, | |
| | 2007 | | 2006 | |
| |
| |
| |
| | (in thousands) | |
Advances to operators for working interests and expenditures | | $ | 1,866 | | $ | — | |
Unproved oil and gas properties | | | 5,961 | | | — | |
Proved oil and gas properties | | | 5,603 | | | 3,917 | |
| |
|
| |
|
| |
Total oil and gas properties | | | 13,430 | | | 3,917 | |
Accumulated depletion and amortization | | | (701 | ) | | — | |
| |
|
| |
|
| |
Oil and gas properties, net | | $ | 12,729 | | $ | 3,917 | |
| |
|
| |
|
| |
Table II - Costs Incurred in Exploration, Property Acquisitions and Development
| | | | | | | |
| | Year ended December 31, | |
| | 2007 | | 2006 | |
| |
|
| |
|
| |
| | (in thousands) | |
Exploratory drilling costs-capitalized | | $ | 13,947 | | $ | 3,917 | |
Exploratory drilling costs-expensed | | | 3,808 | | | 5,898 | |
Geological costs | | | 44 | | | — | |
| |
|
| |
|
| |
| | $ | 17,799 | | $ | 9,815 | |
| |
|
| |
|
| |
F-12
Table III - Reserve Quantity Information
Oil and gas reserves of the Fund have been estimated by an independent petroleum engineer, Ryder Scott Company, L.P., for the year ended December 31, 2007. The reserve estimates for December 31, 2007 were based on estimated future reserves as of December 31, 2007 provided by Ryder Scott Company, L.P. The reserve data at December 31, 2006 was based upon internal engineering estimates due to the timing of the discovery. These reserve disclosures have been prepared in compliance with the Securities and Exchange Commission rules.
Proved reserves are classified as either developed or undeveloped. Proved developed reserves are the quantities expected to be recovered through existing wells with existing equipment and operating methods. There are no proved undeveloped reserves at December 31, 2007 or 2006.
| | | | | | | | | | | | | |
| | December 31, 2007 United States | | December 31, 2006 United States | |
| | Oil (BBLS) | | Gas (MCF) | | Oil (BBLS) | | Gas (MCF) | |
| |
|
|
|
|
|
|
|
|
|
|
| |
| | | | | | | | | | | | | |
Proved developed reserves: | | | | | | | | | | | | | |
Beginning of year | | | 139,320 | | | 2,786,403 | | | — | | | — | |
Discoveries | | | — | | | — | | | 139,320 | | | 2,786,403 | |
Revisions of previous estimates | | | (99,026 | ) | | (1,718,072 | ) | | — | | | — | |
Production | | | (7,851 | ) | | (137,331 | ) | | — | | | — | |
| |
|
|
|
|
|
|
|
|
|
|
| |
End of year | | | 32,443 | | | 931,000 | | | 139,320 | | | 2,786,403 | |
| |
|
|
|
|
|
|
|
|
|
|
| |
Due to the inherent uncertainties and the limited nature of recovery data, estimates of reserve information are subject to change as additional information becomes available.
Table IV - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
Summarized in the following table is information for the Fund with respect to the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves. Future cash inflows are computed by applying year-end prices of oil and natural gas relating to the Fund’s proved reserves to the year-end quantities of those reserves. Future production, development, site restoration and abandonment costs are derived based on current costs assuming continuation of existing economic conditions.
| | | | | | | |
| | December 31, | |
| | 2007 | | 2006 | |
| |
| |
| |
| | (in thousands) | |
Future estimated revenues | | $ | 11,096 | | $ | 24,221 | |
Future estimated production costs | | | (684 | ) | | (1,012 | ) |
Future estimated development costs | | | — | | | (1,581 | ) |
| |
|
| |
|
| |
Future net cash flows | | | 10,412 | | | 21,628 | |
10% annual discount for estimated timing of cash flows | | | (1,350 | ) | | (5,380 | ) |
| |
|
| |
|
| |
Standardized measure of discounted future estimated net cash flows | | $ | 9,062 | | $ | 16,248 | |
| |
|
| |
|
| |
F-13
Table V - Changes in the Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
The changes in present values between years, which can be significant, reflect changes in estimated proved reserve quantities and prices and assumptions used in forecasting production volumes and costs.
| | | | | | | |
| | Year ended December 31, | |
| | 2007 | | 2006 | |
| |
| |
| |
| | (in thousands) | |
Standardized measure beginning of the year | | $ | 16,248 | | $ | — | |
Sales of oil and gas production, net of production costs | | | (1,822 | ) | | — | |
Net changes in prices and production costs | | | 4,823 | | | — | |
Extensions, discoveries, and improved recovery and techniques, less related costs | | | — | | | 15,977 | |
Development costs incurred during the period | | | 1,581 | | | — | |
Revisions of previous reserve quantities estimate | | | (15,737 | ) | | — | |
Accretion of discount | | | 798 | | | 271 | |
Timing and other | | | 3,171 | | | — | |
| |
|
| |
|
| |
Standardized measure end of the year | | $ | 9,062 | | $ | 16,248 | |
| |
|
| |
|
| |
It is necessary to emphasize that the data presented should not be viewed as representing the expected cash flow from, or current value of, existing proved reserves as the computations are based on a large number of estimates. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates and governmental control. Actual future prices and costs are likely to be substantially different from the current price and cost estimates utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitation inherent therein.
F-14
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 O FUND, LLC |
| |
Date: March 21, 2008 | By: | /s/ ROBERT E. SWANSON |
| | Robert E. Swanson |
| | Chief Executive Officer |
| | (Principal Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| | | | |
Signature | | Capacity | | Date |
| |
| |
|
/s/ ROBERT E. SWANSON | | Chief Executive Officer (Principal Executive Officer) | | March 21, 2008 |
| | | | |
Robert E. Swanson | | | | |
| | | | |
/s/ KATHLEEN P. MCSHERRY | | Executive Vice President and Chief Financial Officer | | March 21, 2008 |
| | (Principal Accounting Officer) | | |
Kathleen P. McSherry | | | | |
| | | | |
RIDGEWOOD ENERGY CORPORATION | | | | |
/s/ ROBERT E. SWANSON | | Chief Executive Officer of Manager | | March 21, 2008 |
| | | | |
Robert E. Swanson | | | | |