Attached files
| file | filename |
|---|---|
| EX-32 - Ridgewood Energy O Fund LLC | ex32.htm |
| EX-31.1 - Ridgewood Energy O Fund LLC | ex31_1.htm |
| EX-31.2 - Ridgewood Energy O Fund LLC | ex31_2.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2010
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from _______________________to____________________________
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Commission File No. 000-51924
RIDGEWOOD ENERGY O FUND, LLC
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of
incorporation or organization)
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76-0774429
(I.R.S. Employer
Identification No.)
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14 Philips Parkway, Montvale, NJ 07645
(Address of principal executive offices) (Zip code)
(800) 942-5550
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer
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Accelerated filer
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Non-accelerated filer
(Do not check if a smaller reporting company)
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Smaller reporting company
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x |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x
As of May 11, 2010 the Fund had 870.6486 shares of LLC Membership Interest outstanding.
PART I - FINANCIAL INFORMATION
UNAUDITED CONDENSED BALANCE SHEETS
(in thousands, except share data)
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March 31, 2010
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December 31, 2009
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ASSETS
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Current assets:
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Cash and cash equivalents
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$ | 5,497 | $ | 16,846 | ||||
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Short-term investments in marketable securities
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20,005 | 10,000 | ||||||
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Production receivable
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943 | 1,132 | ||||||
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Other current assets
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366 | 118 | ||||||
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Total current assets
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26,811 | 28,096 | ||||||
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Salvage fund
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1,172 | 1,165 | ||||||
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Oil and gas properties:
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Unproved properties
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6,341 | 5,836 | ||||||
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Proved properties
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16,649 | 16,548 | ||||||
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Less: accumulated depletion and amortization
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(6,942 | ) | (6,409 | ) | ||||
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Total oil and gas properties, net
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16,048 | 15,975 | ||||||
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Total assets
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$ | 44,031 | $ | 45,236 | ||||
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LIABILITIES AND MEMBERS' CAPITAL
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Current liabilities:
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Due to operators
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$ | 1,928 | $ | 975 | ||||
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Accrued expenses
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243 | 56 | ||||||
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Total current liabilities
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2,171 | 1,031 | ||||||
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Asset retirement obligations
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536 | 532 | ||||||
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Total liabilities
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2,707 | 1,563 | ||||||
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Commitments and contingencies (Note 9)
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Members' capital:
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Manager:
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Distributions
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(2,055 | ) | (1,850 | ) | ||||
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Retained earnings
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281 | 155 | ||||||
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Manager's total
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(1,774 | ) | (1,695 | ) | ||||
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Shareholders:
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Capital contributions (935 shares authorized;
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870.6486 issued and outstanding)
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128,990 | 128,990 | ||||||
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Syndication costs
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(14,742 | ) | (14,742 | ) | ||||
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Distributions
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(11,646 | ) | (10,484 | ) | ||||
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Accumulated deficit
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(59,504 | ) | (58,396 | ) | ||||
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Shareholders' total
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43,098 | 45,368 | ||||||
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Total members' capital
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41,324 | 43,673 | ||||||
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Total liabilities and members' capital
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$ | 44,031 | $ | 45,236 | ||||
The accompanying notes are an integral part of these unaudited condensed financial statements.
UNAUDITED CONDENSED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
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Three months ended March 31,
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2010
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2009
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Revenue
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Oil and gas revenue
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$ | 1,552 | $ | 1,223 | ||||
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Expenses
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Depletion and amortization
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533 | 272 | ||||||
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Dry-hole costs
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1,375 | (20 | ) | |||||
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Management fees to affiliate (Note 7)
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431 | 431 | ||||||
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Operating expenses
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123 | 87 | ||||||
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General and administrative expenses
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248 | 141 | ||||||
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Total expenses
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2,710 | 911 | ||||||
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(Loss) income from operations
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(1,158 | ) | 312 | |||||
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Other income
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Interest income
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12 | 80 | ||||||
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Derivative instrument income
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164 | - | ||||||
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Total other income
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176 | 80 | ||||||
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Net (loss) income
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$ | (982 | ) | $ | 392 | |||
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Manager Interest
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Net income
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$ | 126 | $ | 86 | ||||
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Shareholder Interest
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Net (loss) income
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$ | (1,108 | ) | $ | 306 | |||
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Net (loss) income per share
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$ | (1,273 | ) | $ | 351 | |||
The accompanying notes are an integral part of these unaudited condensed financial statements.
UNAUDITED CONDENSED STATEMENTS OF CASH FLOWS
(in thousands)
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Three months ended March 31,
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2010
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2009
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Cash flows from operating activities
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Net (loss) income
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$ | (982 | ) | $ | 392 | |||
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Adjustments to reconcile net (loss) income to net cash
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provided by operating activities:
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Depletion and amortization
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533 | 272 | ||||||
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Dry-hole costs
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1,375 | (20 | ) | |||||
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Accretion expense
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4 | 3 | ||||||
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Derivative instrument income
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(164 | ) | - | |||||
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Interest earned on marketable securities
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(5 | ) | (62 | ) | ||||
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Changes in assets and liabilities:
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Decrease in production receivable
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189 | 152 | ||||||
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Decrease in prepaid royalties
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- | 517 | ||||||
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(Increase) decrease in other current assets
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(53 | ) | 35 | |||||
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Increase in due to operators
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1 | 1 | ||||||
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Increase in accrued expenses
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187 | 25 | ||||||
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Net cash provided by operating activities
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1,085 | 1,315 | ||||||
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Cash flows from investing activities
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Capital expenditures for oil and gas properties
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(1,060 | ) | (4,065 | ) | ||||
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Proceeds from the maturity of investments
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- | 10,094 | ||||||
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Investment in marketable securities
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(10,000 | ) | (6,000 | ) | ||||
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Interest reinvested in salvage fund
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(7 | ) | (7 | ) | ||||
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Net cash (used in) provided by investing activities
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(11,067 | ) | 22 | |||||
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Cash flows from financing activities
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Distributions
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(1,367 | ) | (2,133 | ) | ||||
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Net cash used in financing activities
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(1,367 | ) | (2,133 | ) | ||||
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Net decrease in cash and cash equivalents
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(11,349 | ) | (796 | ) | ||||
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Cash and cash equivalents, beginning of period
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16,846 | 16,818 | ||||||
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Cash and cash equivalents, end of period
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$ | 5,497 | $ | 16,022 | ||||
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Supplemental schedule of non-cash investing activities
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Advances used for capital expenditures in oil and gas
properties reclassified to proved properties and dry-hole costs |
$ | - | $ | 128 | ||||
The accompanying notes are an integral part of these unaudited condensed financial statements.
NOTES TO UNAUDITED CONDENSED 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. The Fund was organized to acquire interests in oil and natural gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico.
The Manager has direct and exclusive control over the management of the Fund’s operations. With respect to project investments, the Manager locates potential projects, conducts due diligence, negotiates with operators and completes the transactions in which the investments are made. The Manager performs, or arranges for the performance of, the management, advisory and administrative services required for Fund operations. Such services include, without limitation, the administration of shareholder accounts, shareholder relations and the preparation, review and dissemination of tax and other financial information. In addition, the Manager provides office space, equipment and facilities and other services necessary for Fund operations. The Manager also engages and manages the 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, 2009 financial statements and notes thereto included in the Fund’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”). The year-end condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by GAAP.
Use of Estimates
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenue and expense during the reporting period. On an ongoing basis, the Manager reviews its estimates, including those related to the fair value of financial instruments, property balances, determination of proved reserves, impairments and asset retirement obligations. Actual results may differ from those estimates.
Cash and Cash Equivalents
All highly liquid investments with maturities, when purchased, of three months or less, are considered cash and cash equivalents. At times, deposits may be in excess of federally insured limits. Effective January 1, 2010, the federally insured limits of the Fund’s deposits are $250 thousand per insured financial institution. At March 31, 2010, the Fund’s balances exceeded federally insured limits by $5.1 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 currently has short-term investments that are classified as held-to-maturity. Held-to-maturity investments are those securities that the Fund has the ability and intent to hold until maturity, and are recorded at cost plus accrued income, adjusted for the amortization of premiums and discounts, which approximates fair value. At March 31, 2010, the Fund had three short-term held-to-maturity investments of $10.0 million and $5.0 million, which mature in May 2010, and $5.0 million, which matures in August 2010.
For all investments, interest income is accrued as earned and amortization of premium or discount, if any, is included in interest income.
Salvage Fund
The Fund deposits in a separate interest-bearing account, or salvage fund, money to provide for the dismantling and removal of production platforms and facilities and plugging and abandoning its wells at the end of their useful lives, in accordance with applicable federal and state laws and regulations. At March 31, 2010, the Fund had investments in U.S. Treasury securities within its salvage fund that are classified as held-to-maturity totaling $1.1 million, which mature in February 2012. Interest earned on the account will become part of the salvage fund. There are no restrictions on withdrawals from the salvage fund.
Oil and Gas Properties
The Fund invests in oil and gas properties, which are operated by unaffiliated entities that are responsible for drilling, administering and producing activities pursuant to the terms of the applicable operating agreements with working interest owners. The Fund’s portion of exploration, drilling, operating and capital equipment expenditures is billed by operators.
The successful efforts method of accounting for oil and gas producing activities is followed. Acquisition costs are capitalized when incurred. Other oil and gas exploration costs, excluding the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending the determination of whether the wells have discovered proved commercial reserves. If proved commercial reserves have not been found, exploratory drilling costs are expensed to dry-hole expense. Costs to develop proved reserves, including the costs of all development wells and related facilities and equipment used in the production of oil and gas, are capitalized. Expenditures for ongoing repairs and maintenance of producing properties are 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 March 31, 2010 and December 31, 2009, amounts recorded in due to operators totaling $1.8 million and $0.9 million, respectively, related to capital expenditures for oil and gas properties.
Advances to Operators for Working Interests and Expenditures
The Fund’s acquisition of a working interest in a well or a project requires it to make a payment to the seller for the Fund’s rights, title and interest. The Fund may be required to advance its share of estimated cash expenditures for the succeeding month’s operation. The Fund accounts for such payments as advances to operators for working interests and expenditures. As drilling costs are incurred, the advances are reclassified to unproved properties.
Asset Retirement Obligations
For oil and gas properties, there are obligations to perform removal and remediation activities when the properties are retired. When a project reaches drilling depth and is determined to be either proved or dry, an asset retirement obligation is incurred. Plug and abandonment costs associated with unsuccessful projects are expensed as dry-hole costs. As indicated above, the Fund maintains a salvage fund to provide for the funding of future asset retirement obligations.
Syndication Costs
Syndication costs are direct costs incurred by the Fund in connection with the offering of the Fund’s shares, including professional fees, selling expenses and administrative costs payable to the Manager, an affiliate of the Manager and unaffiliated broker-dealers, which are reflected on the Fund’s balance sheet as a reduction of shareholders’ capital.
Revenue Recognition and Imbalances
Oil and gas revenues are recognized when oil and gas is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable.
The Fund uses the sales method of accounting for gas production imbalances. The volumes of gas sold may differ from the volumes to which the Fund is entitled based on its interests in the properties. These differences create imbalances that are recognized as a liability only when the properties’ estimated remaining reserves net to the Fund will not be sufficient to enable the underproduced owner to recoup its entitled share through production. The Fund’s recorded liability, if any, would be reflected in other liabilities. No receivables are recorded for those wells where the Fund has taken less than its share of production.
Derivative Instruments
The Fund may periodically utilize derivative instruments to manage the price risk attributable to its oil and gas production. Derivatives are carried on the balance sheet at fair value and recorded as either an asset or liability. Changes in the fair value of the derivatives are recorded currently in earnings unless specific hedge accounting criteria are met. At this time, the Fund has elected not to use hedge accounting for its derivatives and, accordingly, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as derivative instrument income on the statement of operations. The related cash flow impact of the derivative activities are reflected as cash flows from operating activities on the statement of cash flows. See Note 4. “Derivative Instruments,” for more information.
Impairment of Long-Lived Assets
The Fund reviews the value of its oil and gas properties whenever management determines that events and circumstances indicate that the recorded carrying value of properties may not be recoverable. Impairments of producing properties are determined by comparing future net undiscounted cash flows to the net book value at the time of the review. If the net book value exceeds the future net undiscounted cash flows, the carrying value of the property is written down to fair value, which is determined using net discounted future cash flows from the producing property. The Fund provides for impairments on unproved properties when it determines that the property will not be developed or that a permanent impairment in value has occurred. The fair value determinations require considerable judgment and are sensitive to 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. The Fund had no impairments to its oil and gas properties during the three months ended March 31, 2010 and 2009.
Depletion and Amortization
Depletion and amortization of the cost of proved oil and gas properties are calculated using the units-of-production method. Proved developed reserves are used as the base for depleting capitalized costs associated with successful exploratory well costs. The sum of proved developed and proved undeveloped reserves is used as the base for depleting or amortizing leasehold acquisition costs, the costs to acquire proved properties and platform and pipeline costs.
Income Taxes
No provision is made for income taxes in the financial statements. The Fund is a limited liability company, and as such, the Fund’s income or loss is passed through and included in the tax returns of the Fund’s shareholders.
Income and Expense Allocation
Profits and losses are allocated 85% to shareholders in proportion to their relative capital contributions and 15% to the Manager, except for interest income and certain expenses such as dry-hole costs, trust fees, depletion and amortization, which are allocated 99% to shareholders and 1% to the Manager.
3. Recent Accounting Standards
In January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance on improving disclosures about fair value measurements. This guidance has new requirements for disclosures related to recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements in a rollforward reconciliation of Level 3 fair-value measurements. This guidance was effective for the Fund beginning January 1, 2010. The adoption of this guidance did not have a material impact on the Fund’s financial statements. The Level 3 reconciliation disclosures are effective for fiscal years beginning after December 15, 2010, which will be effective for the Fund December 31, 2011. The adoption of the guidance is not expected to have a material impact on the Fund’s financial statements.
4. Derivative Instruments
In January 2010, the Fund entered into a derivative contract for put options relating to the pricing of gas for a portion of its anticipated production. The use of such derivative instruments limits the downside risk of adverse price movements. The Fund has elected not to use hedge accounting for these derivatives and consequently, the derivatives are marked-to-market each quarter with fair value gains and losses recognized currently as derivative instrument income on the statement of operations. The estimated fair value of these contracts is based upon closing exchange prices on the New York Mercantile Exchange (“NYMEX”). See Note 8. “Fair Value Measurements.” The Fund has exposure to credit risk to the extent the derivative instrument counterparty is unable to satisfy its settlement commitment. The Fund actively monitors the creditworthiness of each counterparty and assesses the impact, if any, on its derivative positions.
The put options are carried at their fair value on the balance sheet within “Other current assets” and are settled based upon reported prices on the NYMEX. The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis in the statement of operations under the caption “Derivative instrument income.” Settlements of derivative contracts are reflected in operating activities on the statement of cash flows.
At March 31, 2010, the Fund had outstanding derivative contracts with respect to its future production of gas that are not designated for hedge accounting as detailed in the following table. The Fund had no derivative financial instruments prior to January 2010.
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Production Period
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Type of
Contract
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Volume in
mmbtus
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NYMEX
Contract
Price per
mmbtu
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Estimated
Fair Value
Asset
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(in thousands)
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April 1, 2010 - October 31, 2010
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Put Options
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246,745 | $ | 4.90 | $ | 233 | ||||||||
5. Unproved Properties - Capitalized Exploratory Well Costs
Leasehold acquisition and exploratory drilling costs are capitalized pending determination of whether the well has found proved reserves. Unproved properties are assessed on a quarterly basis by evaluating and monitoring if sufficient progress is made on assessing the reserves. At March 31, 2010, the Fund had no unproved properties with capitalized exploratory well costs in excess of one year. The following table reflects the net changes in unproved properties for the three months ended March 31, 2010 and the year ended December 31, 2009.
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March 31, 2010
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December 31, 2009
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(in thousands)
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Balance, beginning of period
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$ | 5,836 | $ | 984 | ||||
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Additions to capitalized exploratory well costs
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pending the determination of proved reserves
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1,869 | 6,548 | ||||||
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Reclassifications to proved properties based on
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||||||||
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the determination of proved reserves
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- | (1,696 | ) | |||||
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Capitalized exploratory well costs charged to
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dry-hole costs
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(1,364 | ) | - | |||||
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Balance, end of period
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$ | 6,341 | $ | 5,836 | ||||
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, for the three months ended March 31, 2010 and 2009, are detailed in the following table.
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Three months ended March 31,
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Lease Block
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2010
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2009
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(in thousands)
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Targa Project
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$ | 1,364 | $ | - | ||||
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South Timbalier 287
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58 | 328 | ||||||
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Bison Project
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7 | 105 | ||||||
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West Delta 95
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(59 | ) | (458 | ) | ||||
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Other wells
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5 | 5 | ||||||
| $ | 1,375 | $ | (20 | ) | ||||
6. Distributions
Distributions to shareholders are allocated in proportion to the number of shares held. The Manager determines whether available cash from operations, as defined in the LLC Agreement, will be distributed. Such distributions are allocated 85% to the shareholders and 15% to the Manager, as required by the LLC Agreement.
Available cash from dispositions, as defined in the LLC Agreement, will be paid 99% to shareholders and 1% to the Manager until the shareholders have received total distributions equal to their capital contributions. After shareholders have received distributions equal to their capital contributions, 85% of available cash from dispositions will be distributed to shareholders and 15% to the Manager.
7. Related Parties
The LLC Agreement provides that the Manager render management, administrative and advisory services. For such services, the Manager is paid an annual management fee, payable monthly, of 2.5% of total capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund. Management fees for each of the three months ended March 31, 2010 and 2009 were $0.4 million.
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 March 31, 2010 and December 31, 2009, cash and cash equivalents, short-term investments in marketable securities, production receivable, salvage fund and accrued expenses approximate fair value. At March 31, 2010, derivative instruments are recorded at fair value based on Level 2 inputs, as the instrument is an over-the-counter derivative with a third party.
9. Commitments and Contingencies
Capital Commitments
The Fund has entered into multiple agreements for the drilling and development of its investment properties. The estimated capital expenditures associated with these agreements vary depending on the stage of development on a property-by-property basis. As of March 31, 2010, the Fund had committed to spend an additional $15.4 million related to its investment properties, of which $10.2 million is expected to be incurred during the next twelve months.
Environmental Considerations
The exploration for and development of oil and natural gas involves the extraction, production and transportation of materials which, under certain conditions, can be hazardous or cause environmental pollution problems. The Manager and operators of the Fund’s properties are continually taking action they believe appropriate to satisfy applicable federal, state and local environmental regulations and do not currently anticipate that compliance with federal, state and local environmental regulations will have a material adverse effect upon capital expenditures, results of operations or the competitive position of the Fund in the oil and gas industry. However, due to the significant public and governmental interest in environmental matters related to those activities, the Manager cannot predict the effects of possible future legislation, rule changes, or governmental or private claims. At March 31, 2010 and December 31, 2009, there were no known environmental contingencies that required the Fund to record a liability.
Insurance Coverage
The Fund is subject to all risks inherent in the exploration for and development of oil and natural gas. Insurance coverage as is customary for entities engaged in similar operations is maintained, but losses may occur from uninsurable risks or amounts in excess of existing insurance coverage. The occurrence of an event that is not insured or not fully insured could have an adverse impact upon earnings and financial position. Moreover, insurance is obtained as a package covering all of the funds managed by the Manager. Claims made by other funds managed by the Manager can reduce or eliminate insurance for the Fund.
10. Subsequent Events
The Fund has assessed the impact of subsequent events through the date of issuance of its financial statements. In January 2010, the Fund acquired a 2.0% working interest in the Targa Project, an exploratory well. This project began drilling in February 2010 and was determined to be an unsuccessful well, or dry hole, in May 2010. Dry-hole costs of $1.4 million were incurred during the three months ended March 31, 2010. Additional dry-hole costs of $0.9 million are expected to be incurred during the second quarter 2010.
Cautionary Statement Regarding Forward-Looking Statements
Certain statements in this Quarterly Report on Form 10-Q (“Quarterly Report”) and the documents Ridgewood Energy O 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 2009 Annual Report on Form 10-K.
Overview of the Fund’s Business
The Fund is a Delaware limited liability company formed on December 21, 2004 to acquire interests in oil and gas properties located in the United States offshore waters of Texas, Louisiana and Alabama in the Gulf of Mexico. Ridgewood Energy Corporation (“Ridgewood Energy” or the “Manager”) a Delaware corporation, is the Manager. As the Manager, Ridgewood Energy has direct and exclusive control over the management of the Fund’s operations. The Fund’s primary investment objective is to generate cash flow for distribution to its shareholders by generating returns across a portfolio of exploratory or development stage shallow water or deepwater projects. However, the Fund is not required to make distributions to shareholders except as provided in the LLC Agreement.
The Manager performs certain duties on the Fund’s behalf including the evaluation of potential projects for investment and ongoing management, administrative and advisory services associated with these projects. For these services, the Manager receives an annual management fee equal to 2.5% of capital contributions, net of cumulative dry-hole and related well costs incurred by the Fund, payable monthly. The Fund does not currently, nor is there any plan to operate any project in which the Fund participates. The Manager enters into operating agreements with third-party operators for the management of all exploration, development and producing operations, as appropriate. The Manager also participates in distributions.
Revenues are subject to market pricing for oil and natural gas, which has been extremely volatile, and is likely to continue to be volatile in the future. This volatility is caused by numerous factors and market conditions that the Fund cannot control or influence. Therefore, it is impossible to predict the future price of oil and natural gas with any certainty. Low commodity prices could have an adverse affect on the Fund’s future profitability.
Business Update
Information regarding the Fund’s current projects is provided in the following table.
|
Total Spent
|
|
||||||||||
|
Working
|
through
|
Total Estimated
|
|||||||||
|
Interest
|
March 31, 2010
|
Budget
|
Status
|
||||||||
|
Non-producing Properties
|
|||||||||||
|
Liberty Project
|
5.0% | $ | 5,047 | $ | 6,036 |
Completion efforts are ongoing.
|
|||||
|
Production expected July 2010.
|
|||||||||||
|
Alpha Project
|
2.25% | $ | 1,400 | $ | 3,796 |
Completion efforts are ongoing.
|
|||||
|
Production expected second quarter 2011.
|
|||||||||||
|
Aspen Project
|
2.33% | $ | 4,472 | $ | 8,064 |
Drilling a third sidetrack well during second
|
|||||
|
quarter 2010. Will evaluate economics of
|
|||||||||||
|
well completion once sidetrack is completed.
|
|||||||||||
|
Beta Project
|
5.0% | $ | 469 | $ | 7,981 |
Drilling commenced March 2010.
|
|||||
|
Results expected June 2010.
|
|||||||||||
|
Producing Properties
|
|||||||||||
|
South Pelto 9
|
16.7% | $ | 4,926 | $ | 4,926 |
Production commenced September 2007.
|
|||||
|
Eugene Island 346/347 well #1
|
5.0% | $ | 3,496 | $ | 3,496 |
Production commenced June 2008.
|
|||||
|
Eugene Island 346/347 well #2
|
5.0% | $ | 696 | $ | 696 |
Production commenced July 2008.
|
|||||
|
Cobalt Project
|
4.0% | $ | 1,975 | $ | 2,003 |
Production commenced June 2009.
|
|||||
|
Recompletion activities commenced April 2010
|
|||||||||||
|
at an estimated cost of $28 thousand.
|
|||||||||||
|
Dry Holes
|
|||||||||||
|
Targa Project
|
2.0% | $ | 1,364 | $ | 2,230 |
Drilling commenced February 2010.
|
|||||
|
Determined to be an unsuccessful well, or
|
|||||||||||
|
dry hole in May 2010.
|
|||||||||||
Results of Operations
The following table summarizes the Fund’s results of operations for the three months ended March 31, 2010 and 2009, and should be read in conjunction with the Fund’s financial statements and notes thereto included within Item 1 “Financial Statements” in Part I of this Quarterly Report.
|
|
||||||||
|
Three months ended March 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(in thousands)
|
||||||||
|
Revenue
|
||||||||
|
Oil and gas revenue
|
$ | 1,552 | $ | 1,223 | ||||
|
Expenses
|
||||||||
|
Depletion and amortization
|
533 | 272 | ||||||
|
Dry-hole costs
|
1,375 | (20 | ) | |||||
|
Management fees to affiliate
|
431 | 431 | ||||||
|
Operating expenses
|
123 | 87 | ||||||
|
General and administrative expenses
|
248 | 141 | ||||||
|
Total expenses
|
2,710 | 911 | ||||||
|
(Loss) income from operations
|
(1,158 | ) | 312 | |||||
|
Other income
|
||||||||
|
Interest income
|
12 | 80 | ||||||
|
Derivative instrument income
|
164 | - | ||||||
|
Total other income
|
176 | 80 | ||||||
|
Net (loss) income
|
$ | (982 | ) | $ | 392 | |||
Overview. During the three months ended March 31, 2010 and 2009, the Fund had four producing wells and one producing well, respectively. The Cobalt Project commenced production in June 2009 and the Eugene Island 346/347 wells #1 and #2 had were shut-in during the three months ended March 31, 2009 as a result of third quarter 2008 hurricane activity, resuming production in July 2009.
Oil and Gas Revenue. Oil and gas revenue for the three months ended March 31, 2010 was $1.6 million, a $0.3 million increase from the three months ended March 31, 2009. The increase is primarily attributable to the impact of increased average prices totaling $0.4 million, partially offset by decreased sales volumes totaling $0.2 million.
Oil sales volumes were 6 thousand barrels and 7 thousand barrels for the three months ended March 31, 2010 and 2009, respectively. The Fund’s oil prices averaged $77 per barrel during the three months ended March 31, 2010 compared to $39 per barrel during the three months ended March 31, 2009.
Gas sales volumes were 152 thousand mcf and 211 thousand mcf for the three months ended March 31, 2010 and 2009, respectively. The Fund’s gas prices averaged $5.43 per mcf during the three months ended March 31, 2010 compared to $4.82 per mcf during the three months ended March 31, 2009.
The decrease in volumes is primarily attributable to the natural decline in production rates for South Pelto 9, due to the age of the well. This decrease is partially offset by an increase in total productive days, primarily due to the onset of production for the Cobalt Project and the resumption of production for the Eugene Island 346/347 wells #1 and #2.
Depletion and Amortization. Depletion and amortization for the three months ended March 31, 2010 was $0.5 million, an increase of $0.3 million from the three months ended March 31, 2009. The increase resulted from an increase in depletion rates totaling $0.3 million. The increase in depletion rate was attributable to the resumed production for the Eugene Island wells, which has higher cost reserves, partially offset by a decrease in the depletion rate for the South Pelto 9 well as a result of revisions to reserve estimates.
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. The following table summarizes dry-hole costs inclusive of credits.
|
Three months ended March 31,
|
||||||||
|
Lease Block
|
2010
|
2009
|
||||||
|
(in thousands)
|
||||||||
|
Targa Project
|
$ | 1,364 | $ | - | ||||
|
South Timbalier 287
|
58 | 328 | ||||||
|
Bison Project
|
7 | 105 | ||||||
|
West Delta 95
|
(59 | ) | (458 | ) | ||||
|
Other wells
|
5 | 5 | ||||||
| $ | 1,375 | $ | (20 | ) | ||||
Management Fees to Affiliate. Management fees for each of the three months ended March 31, 2010 and 2009 were $0.4 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 include the costs of operating and maintaining wells and related facilities, geological costs and accretion expense as detailed in the following table.
|
Three months ended March 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
(in thousands)
|
||||||||
|
Lease operating expense
|
$ | 76 | $ | 80 | ||||
|
Geological costs
|
43 | 4 | ||||||
|
Accretion expense
|
4 | 3 | ||||||
| $ | 123 | $ | 87 | |||||
Lease operating expense for the three months ended March 31, 2010 and 2009 related to the Fund’s producing properties during each year as outlined above in “Overview”. For the three months ended March 31, 2010, average production cost was $0.34 per mcfe compared to $0.33 per mcfe for the three months ended March 31, 2009. Geological costs for the three months ended March 31, 2010 were related to the Beta and Targa Projects. Geological costs for the three months ended March 31, 2009 were related to the Aspen Project. Accretion expense is related to the asset retirement obligations established for the Fund’s proved properties.
General and Administrative Expenses. General and administrative expenses represent costs specifically identifiable or allocable to the Fund, as detailed in the following table.
|
Three months ended March 31,
|
||||||||
|
2010
|
2009
|
|||||||
|
Insurance expense
|
$ | 203 | $ | 77 | ||||
|
Accounting fees
|
34 | 47 | ||||||
|
Trust fees and other
|
11 | 17 | ||||||
| $ | 248 | $ | 141 | |||||
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.
Interest Income. Interest income is comprised of interest earned on money market accounts and investments in U.S. Treasury securities. Interest income for the three months ended March 31, 2010 was $12 thousand, a $0.1 million decrease from the three months ended March 31, 2009. The decrease was the result of a reduction in average outstanding balances earning interest, due to ongoing capital expenditures for oil and gas properties, coupled with lower interest rates earned.
Derivative Instrument Income. In January 2010, the Fund entered into a derivative contract for put options relating to the pricing of gas for a portion of its anticipated production. The Fund recognizes all unrealized and realized gains and losses related to these contracts on a mark-to-market basis. During the three months ended March 31, 2010, unrealized gains related to these contracts were $0.2 million and realized losses related to these contracts were $6 thousand. There was no derivative activity during the three months ended March 31, 2009.
Capital Resources and Liquidity
Operating Cash Flows
Cash flows provided by operating activities for the three months ended March 31, 2010 were $1.1 million, primarily related to revenue received of $1.7 million and favorable working capital of $0.1 million, partially offset by management fees of $0.4 million, general and administrative expenses of $0.2 million and operating expenses of $0.1 million.
Cash flows provided by operating activities for the three months ended March 31, 2009 were $1.3 million, primarily related to revenue received of $1.4 million and a refund of the MMS prepayments for estimated royalties totaling $0.5 million, partially offset by management fees of $0.4 million and operating and general and administrative expenses totaling $0.2 million.
Investing Cash Flows
Cash flows used in investing activities for the three months ended March 31, 2010 were $11.1 million, primarily related to investments in U.S. Treasury securities of $10.0 million and capital expenditures for oil and gas properties totaling $1.1 million.
Cash flows provided by investing activities for the three months ended March 31, 2009 were $22 thousand, primarily related to proceeds from the maturity of U.S. Treasury securities totaling $10.1 million, principally offset by investments in marketable securities of $6.0 million and capital expenditures for oil and gas properties totaling $4.1 million.
Financing Cash Flows
Cash flows used in financing activities for the three months ended March 31, 2010 were $1.4 million, related to manager and shareholder distributions.
Cash flows used in financing activities for the three months ended March 31, 2009 were $2.1 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 March 31, 2010, the Fund had committed to spend an additional $15.4 million related to its investment properties, of which $10.2 million is expected to be incurred during the next twelve months.
When the Manager makes a decision to participate in an exploratory project, it assumes that the well will be successful and allocates enough capital to budget for the completion of that well and the additional development wells and infrastructure anticipated. If an exploratory well is deemed a dry hole or if it is determined to be un-economical, the capital allocated to the completion of that well and to the development of additional wells is then reallocated to a new project or used to make additional investments.
Capital expenditures for investment properties are funded with the capital raised by the Fund in its private placement offering, which is all the capital it will obtain. The number of projects in which the Fund can invest will naturally be limited, and each unsuccessful project the Fund experiences reduces its ability to generate revenue and exhaust its capital. Typically, the Manager seeks an investment portfolio that combines high and low risk exploratory projects
Liquidity Needs
The Fund’s primary short-term liquidity needs are to fund its operations, inclusive of management fees, and capital expenditures for its investment properties. Operations are funded utilizing operating income, existing cash on-hand, short-term investments and income earned therefrom.
The Manager is entitled to receive an annual management fee from the Fund regardless of the Fund’s profitability in that year. Generally, all or a portion of the management fee is paid from operating income and interest income, although the management fee can be paid out of capital contributions; however, this is not the Fund’s intent.
Distributions, if any, are funded from available cash from operations, as defined in the LLC Agreement, and the frequency and amount are within the Manager’s discretion.
Off-Balance Sheet Arrangements
The Fund had no off-balance sheet arrangements at March 31, 2010 and December 31, 2009 and does not anticipate the use of such arrangements in the future.
Contractual Obligations
The Fund enters into participation and operating agreements with operators. On behalf of the Fund, an operator enters into various contractual commitments pertaining to exploration, development and production activities. The Fund does not negotiate any such contracts. No contractual obligations exist at March 31, 2010 and December 31, 2009 other than those discussed in “Estimated Capital Expenditures” above.
Recent Accounting Pronouncements
See Note 3 of Notes to Unaudited Condensed Financial Statements – “Recent Accounting Standards” contained in this Quarterly Report for a discussion of recent accounting pronouncements.
Not required.
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 March 31, 2010.
There has been no change in the Fund’s internal control over financial reporting that occurred during the three months ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Fund’s internal control over financial reporting.
PART II - OTHER INFORMATION
On August 16, 2006, the Manager of the Fund filed a lawsuit against the former independent registered public accounting firm for the Fund, Perelson Weiner, LLP, (“Perelson”) in New Jersey Superior Court, captioned Ridgewood Energy Corporation v. Perelson Weiner, LLP, Docket No. L-6092-06. The suit alleged professional malpractice and breach of contract in connection with audit and accounting services performed for the Fund by Perelson. Thereafter, Perelson filed a counterclaim against the Manager on October 20, 2006, alleging breach of contract due to unpaid invoices in the amount of $326,554. Discovery is ongoing and a trial date is currently scheduled for May 2010. Legal costs related to this claim are borne by the Manager.
Not required.
None.
None.
None.
|
EXHIBIT
|
|||
|
NUMBER
|
TITLE OF EXHIBIT
|
METHOD OF FILING
|
|
|
31.1
|
Certification of Robert E. Swanson, Chief Executive Officer, pursuant to Exchange Act Rule 13a-14(a).
|
Filed herewith
|
|
|
31.2
|
Certification of Kathleen P. McSherry, Chief Financial Officer, pursuant to Exchange Act Rule 13a-14(a).
|
Filed herewith
|
|
|
32
|
Certifications pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of The Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief Executive Officer of the Fund and Kathleen P. McSherry, Chief Financial Officer of the Fund.
|
Filed herewith
|
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 O FUND, LLC
|
||||||
|
Dated:
|
May 11, 2010
|
By:
|
/s/
|
ROBERT E. SWANSON
|
||
|
Name:
|
Robert E. Swanson
|
|||||
|
Title:
|
Chief Executive Officer
|
|||||
|
(Principal Executive Officer)
|
||||||
|
Dated:
|
May 11, 2010
|
By:
|
/s/
|
KATHLEEN P. MCSHERRY
|
||
|
Name:
|
Kathleen P. McSherry
|
|||||
|
Title:
|
Executive Vice President and Chief Financial Officer
|
|||||
|
(Principal Financial Officer)
|
||||||
16