Attached files
file | filename |
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EX-31.1 - RIDGEWOOD ENERGY K FUND LLC | ex31_1.htm |
EX-31.2 - RIDGEWOOD ENERGY K FUND LLC | ex31_2.htm |
EX-99 - REPORT OF RYDER SCOTT COMPANY, L.P. - RIDGEWOOD ENERGY K FUND LLC | ex99.htm |
EX-32 - RIDGEWOOD ENERGY K FUND LLC | ex32.htm |
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-K
x ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d)
OF
THE SECURITIES EXCHANGE ACT OF 1934
For
the fiscal year ended December 31, 2009
or
o TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES
EXCHANGE ACT OF 1934
For
the transition period from _____ to _____
Commission
File No. 000-51266
RIDGEWOOD
ENERGY K FUND, LLC
(Exact
name of registrant as specified in its charter)
Delaware
(State
or other jurisdiction of
incorporation
or organization)
|
68-0580588
(I.R.S.
Employer
Identification
No.)
|
14
Philips Parkway, Montvale, NJ 07645
(Address
of principal executive offices) (Zip code)
(800)
942-5550
(Registrant’s
telephone number, including area code)
Securities
registered pursuant to Section 12(b) of the Act: None
Securities
registered pursuant to Section 12(g) of the Act:
Shares of
LLC Membership Interest
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes o No x
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Act. Yes o No x
Indicate
by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports) and (2) has been subject to such filing requirements for
the past 90 days. Yes x No o
Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this
chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such
files). Yes o No o
Indicate
by check mark if the disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K (§229.405 of this chapter) is not contained herein, and will not
be contained, to the best of the registrant’s knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is
a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting
company” in Rule 12b-2 of the Exchange Act.
Large
accelerated filer
|
o |
Accelerated
filer
|
o |
Non-accelerated
filer
(Do
not check if a smaller reporting company)
|
o |
Smaller
reporting company
|
x |
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes o No x
There is
no market for the shares of LLC Membership Interest in the Fund. As of March 23,
2010 there are 480.7046 shares of LLC Membership Interest
outstanding.
2009
ANNUAL REPORT ON FORM 10-K
TABLE
OF CONTENTS
PAGE
|
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PART
I
|
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2 | |||
10 | |||
10 | |||
10 | |||
10 | |||
11 | |||
PART
II
|
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11 | |||
11 | |||
11 | |||
16 | |||
16 | |||
16 | |||
16 | |||
17 | |||
PART
III
|
|||
17 | |||
18 | |||
18 | |||
19 | |||
19 | |||
PART
IV
|
|||
20 |
FORWARD-LOOKING
STATEMENTS
Certain
statements in this Annual Report on Form 10-K (“Annual Report”) and the
documents Ridgewood Energy K Fund, LLC (the “Fund”) has incorporated by
reference into this Annual 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.
WHERE
YOU CAN GET MORE INFORMATION
The Fund
files annual, quarterly and current reports and certain other information with
the Securities and Exchange Commission (“SEC”). Persons may read and copy any
materials the Fund files with the SEC at the SEC’s public reference room at 100
F Street, NE, Washington D.C. 20549 on official business days during the hours
of 10 a.m. to 3 p.m. Eastern Time. Information may be obtained from
the public reference room by calling the SEC at 1-800-SEC-0330. The SEC
maintains an internet site that contains reports, proxy and information
statements, and other information regarding issuers that file electronically
with the SEC at http://www.sec.gov.
PART
I
Overview
The Fund
is a Delaware limited liability company (“LLC”) formed on March 1, 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.
The Fund initiated its private placement offering on
April 1, 2004, selling whole and fractional shares of LLC membership interests
(“Shares”) primarily at $150 thousand per
whole Share. There is no public market for the Shares and one is not likely to
develop. In addition, the Shares are subject to material restrictions on
transfer and resale and cannot be transferred or resold except in accordance
with the Fund's limited liability company agreement (the “LLC Agreement”) and
applicable federal and state securities laws. The private placement
offering was terminated on August 1, 2004. The Fund raised $70.9 million and
after payment of $11.1 million in offering fees, commissions and investment
fees, the Fund had $59.8 million for investments and operating
expenses.
Manager
Ridgewood
Energy Corporation (the “Manager” or “Ridgewood Energy”) was founded in
1982. The Manager has direct and exclusive control over the
management of the Fund’s operations. With respect to project investment, the
Manager locates potential projects, conducts due diligence and negotiates and
completes the transactions in which the investments are made. This includes
review of existing title documents, reserve information, and other technical
specifications regarding a project, and review and preparation of participation
agreements and other agreements relating to an investment.
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.
The Fund
is required to pay all other expenses it may incur, including insurance
premiums, expenses of preparing and printing periodic reports for shareholders
and the SEC, commission fees, taxes, outside legal, accounting and consulting
fees, litigation expenses and other expenses. The Fund is required to
reimburse the Manager for all such expenses paid on its behalf.
In
accordance with the LLC Agreement, the Manager is entitled to an annual
management fee, equal to 2.5% of the total shareholder
capital. During 2005, the Manager waived its management fee for the
remaining life of the Fund.
The
Manager is entitled to a 15% interest in cash distributions made by the
Fund. During 2006, the Manager elected to permanently waive its right
to distributions from the Fund.
Business
Strategy
The
Fund’s primary investment objective has been to generate cash flow for
distribution to its shareholders through the acquisition of working interests in
the exploration, production and sale of oil and natural gas. Distributions are
funded from cash flow from operations, and the frequency and amount are within
the Manager’s discretion, subject to available cash from operations, reserve
requirements and Fund operations. A working interest is a percentage
of ownership in an oil and natural gas lease granting its owner the right to
explore, drill and produce oil and natural gas from projects on that lease
block. The Fund has focused on projects that have significant reserve
potential and are projected to have the shortest time period from investment to
first production. The Fund does not operate these projects, and
although it has a vote, it is not in control of the schedule pursuant to which
its projects are developed and completed. Working interest owners are
obligated to pay a corresponding percentage of the cost of leasing, drilling,
producing and operating a well. After royalties are paid, the working
interest also entitles its owner to share in production revenues with other
working interest owners, based on the percentage of working interest
owned.
By virtue
of its acquisition of working interests in various leases, the Fund invests and
participates in exploration and production of oil and natural gas projects in
leases located in the waters of the Gulf of Mexico on the Outer Continental
Shelf (“OCS”). These activities are governed by the Outer Continental Shelf
Lands Act (“OCSLA”) enacted in 1953 and administered by the Mineral Management
Services (“MMS”). The Fund generally has looked to invest in working
interests that have been proposed by larger independent oil and natural gas
companies seeking to minimize their risks by selling a portion of their interest
in the working interest. These investments may require the Fund to
pay a disproportionate part of the drilling costs on the exploratory well of a
project than its working interest would otherwise require. This is called a
promote, which is common in the oil and natural gas exploration industry.
In addition, notwithstanding the sale of an interest to the Fund, the seller may
retain a right for some period of time to payments from sales of oil and natural
gas production from a well or project. This is called an overriding interest,
which is also common in this industry. Notwithstanding any such promote or
overriding interest, the Fund has invested in projects that it believes contain
sufficient commercial quantities of oil or natural gas and which are near
existing oil or natural gas gathering and processing infrastructure and
developed markets where the Fund can sell its oil or natural gas.
For
project investments, the Manager reviews reserve analyses provided by the
operators. The Manager employs individuals in its Houston, Texas
office that can perform significant analysis of the operator’s
information. However, if necessary, the Fund may retain independent
engineers to review the operator’s reserve analysis and/or conduct an
independent review. For producing properties, the Manager engages
independent petroleum engineers to examine and provide reserve estimates on the
Fund’s behalf.
Once the
Manager determines that a particular project (i.e., working interest in a lease
block) is an appropriate investment for the Fund, the Manager enters into a
participation agreement and a joint operating agreement with the other working
interest owners in a lease. Pursuant to the participation agreements
and operating agreements, proposals and decisions are made based on percentage
ownership approvals.
The
Manager, on behalf of the Fund, and other working interest owners retain the
right to make proposals involving certain operational matters associated with a
project. This limits the operator’s inclination to act on its own or
against the interests of the other working interest owners of the
project. In accordance with the Manager’s working interest, the
Manager reviews, discusses and consents to the details of the drilling plan,
monitors progress under such plan, contributes ideas to the design of and budget
for production facilities and then monitors the construction of those
facilities. In addition, the Manager retains the right to review and
audit the operator’s financial records related to the project to ensure the
project is executed according to budget. Once a well is in
production, the Manager continually monitors, evaluates and discusses the well
production rate with the operator.
Manager’s
Investment Committee and Investment Criteria
The
Manager maintains an investment committee, consisting of five members, which
provides operational, scientific and technical oil and gas expertise to the Fund
(the “Investment Committee”). Four members of the investment
committee are based out of the Manager’s Montvale, New Jersey office and one
member is based out of the Manager’s Houston, Texas office. Once the technical
and economic analyses of a potential project are complete and a project has been
deemed to satisfy Ridgewood Energy’s technical criteria, provide an attractive
economic risk/reward ratio, and fit within Ridgewood Energy’s diversification
strategy, final investment approval is made by the Investment
Committee. When reviewing a project for final investment approval,
the Investment Committee seeks to balance the economics of the projects, the
potential sizes of the projects, the diversity of the operators, and the likely
timing of new projects. The Investment Committee also considers the
geological, financial and operating risks of the proposed project and compares
these risks to the existing portfolio of Ridgewood Energy
projects. The Investment Committee further focuses on the initial
well cost relative to the overall revenue potential of the project.
Properties
The Fund
owns working interests in fifteen wells: six are currently producing, one is
currently shut-in, seven have been determined to be dry holes and one was
determined to be fully depleted.
Off-shore
|
|||||||||||||
Location
in
|
Total
Spent
|
||||||||||||
Working
|
Gulf
of
|
Well
|
through
|
||||||||||
Lease Block
|
Interest
|
Mexico
|
Depth
|
12/31/09
|
|||||||||
Producing
Properties
|
(feet)
|
(in
thousands)
|
|||||||||||
South
Marsh Island 111
|
3.75% |
Louisiana
|
11,600 | $ | 1,040 | ||||||||
West
Delta 68
|
3.75% |
Louisiana
|
14,000 | $ | 766 | ||||||||
West
Delta 67
|
3.75% |
Louisiana
|
14,000 | $ | 493 | ||||||||
East
Cameron 299
|
10.0% |
Louisiana
|
21,300 | $ | 18,655 | ||||||||
West
Cameron 556
|
20.0% |
Louisiana
|
17,800 | $ | 11,604 | ||||||||
West
Cameron 76 A-1
|
8.43% |
Louisiana
|
14,000 | $ | 1,775 | ||||||||
Fully
Depleted - 2009
|
|||||||||||||
Vermilion
344
|
3.75% |
Louisiana
|
8,900 | $ | 1,223 |
LLOG
Projects
In 2006,
the Fund acquired a 3.75% working interest in each of six exploratory wells
which are operated by LLOG Exploration Offshore, Inc. (“LLOG”) off the coast of
Louisiana. Of the six wells, the Fund elected not to proceed with one
well and one well was determined to be a dry hole.
The Fund
has capitalized $3.5 million related to the four exploratory wells, which were
determined to be discoveries during 2007. At December 31, 2009, the
Fund has additional budgets for these wells of $0.3 million related to various
recompletion efforts. At December 31, 2009, Vermilion 344 was
determined to be fully depleted by the Fund’s independent petroleum engineer,
Ryder Scott Company, L.P. (“Ryder Scott”). During the years ended
December 31, 2009 and 2008, the Fund recorded impairments related to Vermilion
344 totaling $0.5 million and $0.6 million, respectively.
South
Marsh Island 111
|
Discovery
July 2007; Production
commenced
February 2009
|
Vermilion
344
|
Discovery
January 2007; Production
commenced
December 2008; Fully
depleted
at December 31, 2009
|
West
Delta 68
|
Discovery
March 2007; Production
commenced
July 2008
|
West
Delta 67
|
Discovery
November 2007; Production
commenced
July 2008
|
East
Cameron 299 / West Cameron 556
The Fund
acquired from Millennium Offshore Group (“MOGI”) a 10.0% working interest in the
East Cameron 299 field and a 20.0% working interest in West Cameron 556 at a
total cost of $30.3 million. During 2005, MOGI sold its interests in
the East Cameron 299 and West Cameron 556 wells, which are currently operated by
ATP Oil and Gas Corporation (“ATP”). Within the East Cameron
299/West Cameron 556 field, there are currently two producing wells and one well
is shut-in pending a workover.
During
August 2009, a valve repair was required on the pipeline through which the East
Cameron 299/West Cameron 556 production flows. Accordingly, these
wells did not produce for several weeks during the third quarter
2009. Production rates continue to decrease for the East Cameron 299
well, as its initial zone is nearly depleted. A recompletion of the
well will be needed in order to access the reserves in the well’s lower zone.
The Fund and its joint interest partners are evaluating the recompletion
options. The Fund recorded impairment charges totaling $1.9 million
during the year ended December 31, 2009 after re-considering its plans to bring
a second East Cameron well on production under current market conditions. To date, the
Fund has recorded impairments of $14.6 million related to East Cameron 299 and
West Cameron 556.
West
Cameron 76 A-1
In 2007,
the Fund acquired an 8.43% working interest in the West Cameron 76 A-1 well,
which began producing in October 2007. The Fund capitalized $1.8
million related to this well.
Working
Interest in Oil and Natural Gas Leases
Existing projects, and future projects, if any, are
expected to be located in the waters of the Gulf of Mexico offshore from
Texas, Louisiana and Alabama on the OCS. The OCSLA, which was enacted in
1953, governs certain activities with respect to working interests and the
exploration of oil and natural gas in the OCS. See further discussion
under the heading “Regulation” in this Item 1. “Business”.
As part
of the leasing activity and as required by the OCSLA, the leases auctioned
include specified lease terms such as the length of the lease, the amount of
royalty to be paid, lease cancellation and suspension, and, to a degree, the
planned activities of exploration and production to be conducted by the
lessee.
Leases in
the OCS are generally issued for a primary lease term of 5, 8 or 10 years
depending on the water depth of the lease block. The 5-year lease term is for
blocks in water depths generally less than 400 meters, 8 years for depths
between 400 meters and 800 meters and 10 years for depths in excess of 800
meters. During this primary lease term, except in limited circumstances, lessees
are not subject to any particular requirements to conduct exploratory or
development activities. However, once a lessee drills a well and begins
production, the lease term is extended for the duration of commercial
production.
The
lessee of a particular block, for the term of the lease, has the right to drill
and develop exploratory wells and conduct other activities throughout the block.
If the initial well on the block is successful, a lessee, or third-party
operator for a project, may conduct additional geological studies and may
determine to drill additional or development wells. If a development well is to
be drilled in the block, each lessee owning working interests in the block must
be offered the opportunity to participate in, and cover the costs of, the
development well up to that particular lessee’s working interest ownership
percentage.
Generally,
working interests in an offshore natural gas lease under the OCSLA pay a 16.67%
or 18.75% royalty to the MMS for shallow-water projects, dependent upon the
lease date, and a 12.5% royalty to the MMS for deepwater projects. Therefore,
the net revenue interest of the holders of 100% of the working interest in the
projects in which the Fund will invest is between 81.25% and 83.33% of the total
revenue for shallow-water projects and 87.5% of the total revenue for deepwater
projects, and such net revenue amount is further reduced by any other royalty
burdens that apply to a lease block. However, as described below, the MMS has
adopted royalty relief for existing OCS leases for those who drill deep oil and
natural gas projects. Other than MMS royalties, the Fund does not
have material royalty burdens.
Mineral
Management Services Deep Gas Royalty Incentive
On
January 26, 2004, the MMS promulgated a rule providing incentives for companies
to increase deep oil and natural gas production in the Gulf of Mexico (the
“Royalty Relief Rule”). Under the Royalty Relief Rule, lessees will be eligible
for royalty relief on their existing leases if they drill and perforate wells
for new and deeper reserves at depths greater than 15,000 feet subsea. In
addition, an even larger royalty relief would be available for wells drilled and
perforated deeper than 18,000 feet subsea. It should be noted that the Royalty
Relief Rule does not extend to deep waters of the Gulf of Mexico off the
continental shelf nor does it apply if the price of natural gas exceeds $10.48
Million British Thermal Units (“mmbtu”) adjusted annually for inflation. The
Royalty Relief Rule is limited to leases in a water depth less than 656 feet, or
200 meters.
In addition to the Royalty Relief Rule promulgated by
the MMS, the Deep Water Royalty Relief Act of 1995 (the “Deepwater Relief
Act”) was enacted to promote exploration and production of natural gas and oil
in the deepwater of the Gulf of Mexico and relieves eligible leases from paying
royalties to the U.S. Government on certain defined amounts of deepwater
production. The Deepwater Relief Act expired in the year 2000 but was
extended by the MMS to promote continued interest in deepwater. For purposes of
royalty relief, under the Deepwater Relief Act, the MMS defines deepwater as
depths in excess of 656 feet or 200 meters. In order for a lease to
be eligible for royalty relief, under the Deepwater Relief Act, it must be
located in the Gulf of Mexico and west of 87 degrees and 30 minutes West
longitude (essentially the Florida-Alabama boundary).
Currently,
for leases entered into after November 2000, the MMS assigns a lease a specific
volume of royalty suspension based on how the suspension amount would affect the
economics of the lease’s development. Any such royalty
suspension applicable to a particular lease is generally set forth in the lease
auction materials prepared by the MMS. The amount of the suspension,
if any, is not determined by water depth levels (as it had in the past) but
rather based upon the MMS’ view of the characteristics and economics of the
project. For example, projects deemed relatively secure and safe such
as those near existing transportation infrastructure may receive no royalty
relief while a similar project far away from any such infrastructure or in an
area deemed more risky may receive significant royalty
relief. As a result, unlike the royalty relief associated with
deep drilling in shallow waters, there is no formulaic or predictable means of
determining in advance whether and to what extent royalty relief would be
available for a potential deepwater project.
Oil
and Natural Gas Agreements
The Fund
has entered into a month-to-month agreement with a third-party marketer, who is
currently marketing and selling the Fund’s proportionate share of oil and
natural gas to the public market. The Fund is receiving market prices for
the oil and natural gas it sells. All of the Fund’s current projects are near
existing transportation infrastructure and pipelines. The
Manager believes that it is likely that oil and natural gas from the Fund’s
future projects will have access to pipeline transportation and can be marketed
in a similar fashion.
Operator
The
projects in which the Fund has invested are operated and controlled by
unaffiliated third-party entities acting as operators. The operators are
responsible for drilling, administration and production activities for leases
jointly owned by working interest owners and act on behalf of all working
interest owners under the terms of the applicable operating agreement. In
certain circumstances, operators will enter into agreements with independent
third-party subcontractors and suppliers to provide the various services
required for operating leases. Currently, the
Fund's producing properties are operated by ATP, BHP Billiton Petroleum, Ltd.,
and LLOG.
Because
the Fund does not operate any of the projects in which it has acquired an
interest, shareholders not only bear the risk that the Manager will be able to
select suitable projects, but also that once selected, such projects will be
managed prudently, efficiently and fairly by the operators.
Insurance
The
Manager has obtained and maintains what it believes to be adequate insurance for
the funds that it manages. The Manager has obtained hazard, property,
general liability and other insurance in commercially reasonable amounts to
cover its projects, as well as general liability, directors’ and officers’
liability and similar coverage for its business operations. However, there is no
assurance that such insurance will be adequate to protect the Fund from material
losses related to the projects. Further, for the policy period August
2009 through July 2010, the Manager did not obtain coverage for named
windstorm. As a result of the losses underwriters incurred from
claims arising from Hurricane Ike, a named windstorm in September 2008, the
Manager determined that the premiums sought by underwriters for, and the
deductibles applicable to, coverage for named windstorm made obtaining such
coverage for such policy period prohibitively expensive. In addition,
the Manager’s past practice has been to obtain insurance as a package that is
intended to cover most, if not all, of the funds under its management. The
Manager will reevaluate its coverage on an annual basis. While the
Manager believes it has obtained adequate insurance in accordance with customary
industry practices, the possibility exists, depending on the extent of the
incident, that insurance coverage may not be sufficient to cover all
losses. In addition, depending on the extent, nature and payment of any
claims to the Fund’s affiliates, yearly insurance limits may be exhausted and
become insufficient to cover a claim made by the Fund in a given
year.
Salvage
Fund
As to
projects in which the Fund owns a working interest, the Fund deposits in a
separate interest-bearing account, or salvage fund, which is in the nature of a
sinking fund, cash to provide for the Fund’s proportionate share of the
anticipated cost of dismantling production platforms and facilities, plugging
and abandoning the wells and removing the platforms, facilities and wells in
respect of the projects after the end of their useful lives, in accordance with
applicable federal and state laws and regulations. The Fund has deposited
$1.0 million from capital contributions into a salvage fund, which along with
interest earned on this account, the Fund estimates to be sufficient to meet the
Fund’s potential requirements. If, at any time, the Manager determines the
salvage fund will not be sufficient to cover the Fund’s proportionate share of
expense, the Fund may transfer amounts from capital contributions or operating
income to fund the deficit. Payments to the salvage fund will reduce the amount
of cash distributions that may be made to investors by the Fund. Any
portion of a salvage fund that remains after the Fund pays its share of the
actual salvage cost will be distributed to the shareholders. There are no
restrictions on the withdrawal or use of the salvage fund.
Seasonality
Generally,
the Fund’s business operations are not subject to seasonal fluctuations in the
demand for oil and natural gas that would result in more of the Fund’s oil and
natural gas being sold, or likely to be sold, during one or more particular
months or seasons. Once a project is producing, the operator of the project
extracts oil and natural gas reserves throughout the year. Once extracted, oil
and natural gas can be sold at any time during the year.
The
Fund’s properties are located in the Gulf of Mexico; therefore its operations
and cash flows may be significantly impacted by hurricanes and other inclement
weather. Such events may also have a detrimental impact on
third-party pipelines and processing facilities, upon which the Fund relies to
transport and process the oil and natural gas it produces. The National
Hurricane Center defines hurricane season in the Gulf of Mexico as June 1st
through November 30th. During third quarter 2008, two hurricanes struck in the
Gulf of Mexico, which significantly impacted the Fund’s operations. These two
storms, Hurricanes Gustav and Ike, came ashore in Louisiana and Texas,
respectively, and caused production curtailments due to damage to third-party
pipelines and disrupted the operations of crews that could assess and repair the
damage. While the Fund’s platforms avoided major damage, the Fund’s production
was curtailed from the time personnel were evacuated for safety purposes, until
assessment and repair to the Fund’s platforms were completed and until repairs
to third-party pipelines and facilities, for which the Fund was not responsible,
were completed. As a result, East Cameron 299/West Cameron 556
and West Delta 67/68 were shut-in for approximately one month, with production
resuming during October 2008 and West Cameron 76 was shut-in for approximately
three months, with production resuming during October 2008. The Fund
did not experience any damage or shut-ins, or production stoppages, due to
hurricane activity during 2009.
Customers
All of
the oil and natural gas production from the Fund’s producing properties is sold
by a third party. As a result, the Fund did not contract to sell oil
and natural gas to customers. Therefore, the Fund had no customers or
any one or few major customers upon which it depends.
Energy
Prices
Historically,
the markets for and prices of oil and natural gas have been extremely volatile,
and they are 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. The Fund has not engaged in any price
risk management programs or hedges.
Competition
Strong
competition exists in the acquisition of oil and natural gas leases and in all
sectors of the oil and natural gas exploration and production industry. Although
the Fund does not compete for lease acquisitions from the MMS, it does compete
with other companies for the acquisition of percentage ownership interests in
oil and natural gas working interests in the secondary market.
In many
instances, the Fund competes for projects with large independent oil and natural
gas producers who generally have significantly greater access to capital
resources, have a larger staff, and more experience in oil and natural gas
exploration and production than the Fund. As a result, these larger companies
are in a position that they could outbid the Fund for a project. However,
because these companies are so large and have such significant resources, they
tend to focus more on projects that are larger, have greater reserve potential,
and cost significantly more to explore and develop. The focus of these companies
on larger projects does not necessarily mean that they will not investigate
and/or acquire projects for which the Fund typically competes. The Manager is
often able to win project participations ahead of such competitors for the
following reasons: (i) Ridgewood Energy has an investment process
that is not subject to the more layered decision-making processes that typically
exist within large oil and gas companies; such processes enable Ridgewood Energy
to assimilate financial, seismic and operational data in relation to a
prospective project and assess the terms on which the project is being offered,
which the Fund believes puts Ridgewood Energy in a position to reach an
investment decision well in advance of most large oil and gas companies, (ii)
Ridgewood Energy is one of the most active exploration and production
participants in the Gulf of Mexico, and as a result the management team is in
regular contact with all the major operators and is therefore able to contribute
valuable perspectives both from a geological and operational viewpoint and (iii)
Ridgewood Energy is typically not viewed as a competitor by the syndicating
operator as Ridgewood Energy does not participate in lease block sales but only
invests in drill-ready syndicated projects.
Employees
The Fund
has no employees as the Manager operates and manages the Fund.
Offices
The
principal executive office of the Fund and the Manager is located at 14 Philips
Parkway, Montvale, NJ 07645, and its phone number is 800-942-5550. The
Manager leases additional office space at 11700 Old Katy Road, Houston, TX
77079. In addition, the Manager maintains leases for other offices
that are used for administrative purposes.
Regulation
Oil and
natural gas exploration, development and production activities are subject to
extensive federal and state laws and regulations. Regulations governing
exploration and development activities require, among other things, the Fund’s
operators to obtain permits to drill projects and to meet bonding, insurance and
environmental requirements in order to drill, own or operate projects. In
addition, the location of projects, the method of drilling and casing projects,
the restoration of properties upon which projects are drilled and the plugging
and abandoning of projects are also subject to regulations.
The
Fund’s projects are located in the offshore waters of the Gulf of Mexico on the
OCS. The Fund’s operations and activities are therefore governed by the OCSLA
and certain other laws and regulations described herein.
Outer
Continental Shelf Lands Act
Under the
OCSLA, the United States federal government has jurisdiction over oil and
natural gas development on the OCS. As a result, the United States Secretary of
the Interior is empowered to sell exploration, development and production leases
of a defined submerged area of the OCS, or a block, through a competitive
bidding process. Such activity is conducted by the MMS, an agency of the United
States Department of Interior. The MMS administers federal offshore leases
pursuant to regulations promulgated under the OCSLA. Lessees must obtain MMS
approval for exploration, development and production plans prior to the
commencement of offshore operations. In addition, approvals and permits are
required from other agencies such as the US Coast Guard, the Army Corps of
Engineers and the Environmental Protection Agency. The Fund is not involved in
the process of obtaining any such approvals or permits. Offshore
operations are subject to numerous regulatory requirements, including stringent
engineering and construction specifications related to offshore production
facilities and pipelines and safety-related regulations concerning the design
and operating procedures of these facilities and pipelines. MMS regulations also
restrict the flaring or venting of production and proposed regulations would
prohibit the flaring of liquid hydrocarbons and oil without prior
authorization.
The MMS
has also imposed regulations governing the plugging and abandonment of wells
located offshore and the installation and removal of all production facilities.
Under certain circumstances, the MMS may require operations on federal leases to
be suspended or terminated. Any such suspension or termination could adversely
affect the Fund’s operations and interests.
The MMS
conducts auctions for lease blocks of submerged areas offshore. As part of the
leasing activity and as required by the OCSLA, the leases auctioned include
specified lease terms such as the length of the lease, the amount of royalty to
be paid, lease cancellation and suspension, and, to a degree, the planned
activities of exploration and production to be conducted by the lessee. In
addition, the OCSLA grants the Secretary of the Interior continuing oversight
and approval authority over exploration plans throughout the term of the
lease.
Sales and Transportation of Oil and
Natural Gas
The Fund
sells its proportionate share of oil and natural gas through the operator on the
Fund’s behalf to the market and receives market prices from such sales. These
sales are not currently subject to regulation by any federal or state agency.
However, in order for the Fund to make such sales it is dependent upon
unaffiliated pipeline companies whose rates, terms and conditions of transport
are subject to regulation by the Federal Energy Regulatory Commission (“FERC”).
The rates, terms and conditions are regulated by FERC pursuant to a variety of
statutes including the OCSLA, the Natural Gas Policy Act and the Energy Policy
Act of 1992. Generally, depending on certain factors, pipelines can charge rates
that are either market-based or cost-of-service. In some circumstances, rates
can be agreed upon pursuant to settlement. Thus, the rates that pipelines charge
the Fund, although regulated, are beyond the Fund’s control. Nevertheless, such
rates would apply uniformly to all transporters on that pipeline and, as a
result, management does not anticipate that the impact to the Fund of any
changes in such rates, terms or conditions would be materially different than
the impact upon other oil or natural gas producers and marketers.
Environmental
Matters and Regulation
The
Fund’s operations are subject to pervasive environmental laws and regulations
governing the discharge of materials into the air and water and the protection
of aquatic species and habitats. However, although it shares the liability along
with its other working interest owners for any environmental damage, most of the
activities to which these environmental laws and regulations apply are conducted
by the operator on the Fund’s behalf. Nevertheless, environmental laws and
regulations to which its operations are subject may require the Fund, or the
operator, to acquire permits to commence drilling operations, restrict or
prohibit the release of certain materials or substances into the environment,
impose the installation of certain environmental control devices, require
certain remedial measures to prevent pollution and other discharges such as the
plugging of abandoned projects and, finally, impose in some instances severe
penalties, fines and liabilities for the environmental damage that may be caused
by the Fund’s projects.
Some of
the environmental laws that apply to oil and natural gas exploration and
production are:
The
Oil Pollution Act. The Oil Pollution
Act of 1990, as amended (the “OPA”), amends Section 311 of the Federal Water
Pollution Control Act of 1972 (the “Clean Water Act”) and was enacted in
response to the numerous tanker spills, including the Exxon Valdez that occurred
in the 1980s. Among other things, the OPA clarifies the federal response
authority to, and increases penalties for, such spills. The OPA establishes a
new liability regime for oil pollution incidents in the aquatic environment.
Essentially, the OPA provides that a responsible party for a vessel or facility
from which oil is discharged or that poses a substantial threat of a discharge
could be liable for certain specified damages resulting from a discharge of oil,
including clean-up and remediation, loss of subsistence use of natural
resources, real or personal property damages, as well as certain public and
private damages. A responsible party includes a lessee of an offshore
facility.
The OPA
also requires a responsible party to submit proof of its financial
responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill. Under the OPA, parties responsible
for offshore facilities must provide financial assurance of at least $35 million
to address oil spills and associated damages. In certain limited
circumstances, that amount may be increased to $150 million. As indicated
earlier, the Fund has not been required to make any such showing to the MMS, as
the operators are responsible for such compliance. However, notwithstanding the
operators’ responsibility for compliance, in the event of an oil spill, the
Fund, along with the operators and other working interest owners, could be
liable under the OPA for the resulting environmental damage.
Clean
Water Act. Generally, the Clean Water Act imposes liability
for the unauthorized discharge of pollutants including petroleum products into
the surface and coastal U.S. waters except in strict conformance with discharge
permits issued by the federal or state if applicable agency. Regulations
governing water discharges also impose other requirements, such as the
obligation to prepare spill response plans. The Fund’s operators are responsible
for compliance with the Clean Water Act although the Fund may be liable for any
failure of the operator to do so.
Federal
Clean Air Act. The Federal Clean Air Act of 1970, as amended
(the “Clean Air Act”), restricts the emission of certain air pollutants. Prior
to constructing new facilities, permits may be required before work can commence
and existing facilities may be required to incur additional capital costs to add
equipment to ensure and maintain compliance. As a result, the Fund’s operations
may be required to incur additional costs to comply with the Clean Air
Act.
Other
Environmental Laws. In addition to the above, the Fund’s
operations may be subject to the Resource
Conservation and Recovery Act of 1976, as amended, which regulates the
generation, transportation, treatment, storage, disposal and cleanup of certain
hazardous wastes, as well as the Comprehensive
Environmental Response, Compensation and Liability Act which imposes
joint and several liability without regard to fault or legality of conduct on
classes of persons who are considered responsible for the release of a hazardous
substance into the environment.
The above
represents a brief outline of the major environmental laws that may apply to the
Fund’s operations. The Fund believes that its operators are in compliance with
each of these environmental laws and the regulations promulgated
thereunder. The Fund does not believe that the costs of compliance
with applicable environmental laws, including federal, state and local laws,
will have a material adverse impact on its financial condition and/or
operations.
Not
required.
Not
applicable.
The
information regarding the Fund’s properties that is contained in Item 1.
“Business” of this Annual Report under the heading “Properties” is incorporated
herein by reference.
Unaudited
Oil and Gas Reserve Quantities
The
preparation of the Fund’s oil and gas reserve estimates are completed in
accordance with the Fund’s internal control procedures over reserve
estimation. The Fund’s management controls over proved reserve estimation
include: 1) verification of input data that is provided to an independent
petroleum engineering firm, 2) engagement of well-qualified and independent
reservoir engineers for preparation of reserve reports annually in accordance
with SEC reserve estimation guidelines and 3) a review of the reserve estimates
by the Manager.
The
Fund’s reserve estimates at December 31, 2009 and 2008 were prepared by Ryder
Scott, an independent petroleum engineering firm. The information
regarding the qualifications of the petroleum engineer is included within the
report from Ryder Scott, which is included as Exhibit 99 of this Annual Report,
and is incorporated herein by reference.
Proved
oil and gas reserves are the estimated quantities of oil and natural gas, which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed oil and gas reserves are those
reserves expected to be recovered through existing wells with existing equipment
and operating methods. The information regarding the Fund’s proved
reserves, which is contained in Item 7. “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” of this Annual Report under the
heading “Critical Accounting Estimates – Proved Reserves”, is incorporated
herein by reference. The information regarding the Fund’s unaudited net
quantities of proved developed and undeveloped reserves, which is contained in
Table III in the “Supplementary Financial Information – Information about Oil
and Gas Producing Activities – Unaudited” included in Item 15. “Exhibits,
Financial Statement Schedules” of this Annual Report, is incorporated herein by
reference.
Proved Undeveloped Reserves.
At December 31, 2009, the Fund had approximately 400 barrels and 80 thousand mcf
of proved undeveloped oil and natural gas reserves, respectively, attributable
to South Marsh Island 111. The Fund is currently evaluating the
development alternatives for these proved undeveloped reserves. At
December 31, 2008, the Fund had approximately 10 thousand barrels and 593
thousand mcf of proved undeveloped oil and natural gas reserves, respectively,
attributable to East Cameron 299 and West Cameron 556. During the year ended
December 31, 2009, it was determined that it was not economical to develop the
proved undeveloped reserves attributable to East Cameron 299 and West Cameron
556.
Production
and Prices
The
information regarding the Fund’s production of oil and natural gas, and certain
price and cost information for the years ended December 31, 2009 and 2008 that
is contained in Item 7. “Management’s Discussion and Analysis of Financial
Condition and Results of Operations” of this Annual Report under the headings
“Results of Operations – Oil and Gas Revenue” and “Results of Operations –
Operating Expenses” is incorporated herein by reference.
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 set for May 2010. Legal costs related
to this claim are borne by the Manager.
PART
II
There is
currently no established public trading market for the Shares. As of
March 23, 2010, there were 855 shareholders of record of the Fund.
Distributions
are made in accordance with the provisions of the LLC Agreement. At
various times throughout the year, the Manager determines whether there is
sufficient available cash as defined in the LLC Agreement, for distribution to
shareholders. There is, however, no requirement to distribute
available cash and as such, available cash is distributed to the extent and at
such times as the Manager believes is advisable. During the years
ended December 31, 2009 and 2008, the Fund paid distributions to shareholders
totaling $2.1 million and $3.8 million, respectively. During 2006,
the Manager waived its right to cash distributions for the remaining life of the
Fund.
Not
required.
Overview
of the Fund’s Business
The Fund
was organized to acquire interests in oil and gas properties located in the
United States offshore waters of Texas, Louisiana and Alabama in the Gulf of
Mexico. The 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 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. 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. See also Item 1. “Business” for
additional information regarding the projects of the Fund.
Revenues
are subject to the market pricing for oil and natural gas, which has been
extremely volatile, and are 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.
Critical
Accounting Estimates
The
discussion and analysis of the Fund’s financial condition and results of
operations are based upon the Fund’s financial statements, which have been
prepared in conformity with accounting principles generally accepted in the
United States of America (“GAAP”). In preparing these financial
statements, the Fund is required to make certain estimates, judgments and
assumptions. These estimates, judgments and assumptions affect the reported
amounts of the Fund’s assets and liabilities, including the disclosure of
contingent assets and liabilities, at the date of the financial statements and
the reported amounts of its revenues and expenses during the periods
presented. The Fund evaluates these estimates and assumptions on an
ongoing basis. The Fund bases its estimates and assumptions on historical
experience and on various other factors that the Fund believes to be reasonable
at the time the estimates and assumptions are made. However, future events and
actual results may differ from these estimates and assumptions and such
differences may have a material impact on the results of operations, financial
position, or cash flows. See Note 2 of Notes to Financial
Statements – “Summary of Significant Accounting Policies” contained in Item 8.
“Financial Statements and Supplementary Data” contained in this Annual Report
for a discussion of the Fund’s significant accounting policies.
Accounting
for Exploration and Development Costs
Exploration
and production activities are accounted for using the successful efforts method.
Costs of acquiring unproved and proved oil and natural gas leasehold acreage,
including lease bonuses, brokers’ fees and other related costs are capitalized.
Annual lease rentals, exploration expenses and dry-hole costs are expensed as
incurred. Costs of drilling and equipping productive wells and related
production facilities are capitalized.
The costs
of exploratory and developmental wells are capitalized pending determination of
whether proved reserves have been found. Drilling costs remain capitalized after
drilling is completed if (1) the well has found a sufficient quantity of
reserves to justify completion as a producing well and (2) sufficient
progress is being made in assessing the reserves and the economic and operating
viability of the project. If either of those criteria is not met, or if there is
substantial doubt about the economic or operational viability of the project,
the capitalized well costs are charged to expense as dry-hole costs. Indicators
of sufficient progress in assessing reserves and the economic and operating
viability of a project include: commitment of project personnel; active
negotiations for sales contracts with customers; negotiations with governments,
operators and contractors; and firm plans for additional drilling and other
factors.
Unproved
Property
Unproved
property is comprised of capital costs incurred for undeveloped acreage, wells
and production facilities in progress and wells pending determination. These
costs are initially excluded from the depletion base until the outcome of the
project has been determined, or generally until it is known whether proved
reserves will or will not be assigned to the property. The Fund assesses
all items in its unproved property balance on an ongoing basis for possible
impairment or reduction in value.
Proved
Reserves
Annually,
the Fund engages an independent petroleum engineer, Ryder Scott, to perform a
comprehensive study of the Fund’s producing properties to determine the
quantities of reserves and the period over which such reserves will be
recoverable. The Fund’s estimates of proved reserves are based on the
quantities of oil and natural gas that geological and engineering data
demonstrate, with reasonable certainty, to be recoverable in future years from
known reservoirs under existing economic and operating conditions. However,
there are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future revenues, rates of production and timing of
development expenditures, including many factors beyond the Fund’s control. The
estimation process is very complex and relies on assumptions and subjective
interpretations of available geologic, geophysical, engineering and production
data and the accuracy of reserve estimates is a function of the quality and
quantity of available data, engineering and geological interpretation, and
judgment. In addition, as a result of volatility and changing market conditions,
commodity prices and future development costs will change from period to period,
causing estimates of proved reserves and future net revenues to
change. Estimates of proved reserves are key components of the Fund’s
most significant financial estimates involving its rate for recording
depreciation, depletion and amortization.
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, a liability is recognized for the present value of asset
retirement obligations once reasonably estimable. The Fund capitalizes the
associated asset retirement costs as part of the carrying amount of its proved
properties. Plug and abandonment costs associated with unsuccessful projects are
expensed as dry-hole costs.
Impairment
of Long-Lived Assets
The Fund
reviews the value of its oil and gas properties whenever management determines
that events and circumstances indicate that the recorded carrying value of
properties may not be recoverable. Impairments of producing
properties are determined by comparing future net undiscounted cash flows to the
net book value at the end of each period. If the net book value
exceeds the future net undiscounted cash flows, the carrying value of the
property is written down to “fair value,” which is determined using net
discounted future cash flows from the producing property. Different
pricing assumptions, reserve estimates or discount rates could result in a
different calculated impairment. The Fund provides for impairments on
unproved properties when it determines that the property will not be developed
or a permanent impairment in value has occurred. Given the volatility
of oil and 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.
Results
of Operations
The
following table summarizes the Fund’s results of operations for the years ended
December 31, 2009 and 2008 and should be read in conjunction with the Fund’s
financial statements and the notes thereto included within Item 8. “Financial
Statements and Supplementary Data” in this Annual Report.
Year
ended December 31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Revenue
|
||||||||
Oil
and gas revenue
|
$ | 2,385 | $ | 4,810 | ||||
Expenses
|
||||||||
Depletion
and amortization
|
2,895 | 2,357 | ||||||
Impairment
of proved properties
|
2,394 | 568 | ||||||
Operating
expenses
|
613 | 468 | ||||||
General
and administrative expenses
|
273 | 296 | ||||||
Total
expenses
|
6,175 | 3,689 | ||||||
(Loss)
income from operations
|
(3,790 | ) | 1,121 | |||||
Other
income
|
||||||||
Interest
income
|
44 | 137 | ||||||
Net
(loss) income
|
$ | (3,746 | ) | $ | 1,258 |
Overview. During the year ended December 31, 2009, the Fund
had seven producing wells, East Cameron 299, which commenced production during
2004, West Cameron 556, which commenced production during 2005, West Cameron 76
A-1, which commenced production during 2007, West Delta 67/68, which commenced
production in July 2008, Vermilion 344 which commenced production in December
2008 and South Marsh Island 111 which commenced production in February
2009. Vermilion 344 was determined to be fully depleted at December
31, 2009. During the year ended December 31, 2008, the Fund had six
producing wells. Oil and gas sales were all
located within the United States.
Oil and Gas
Revenue. Oil and gas revenue for the year ended December 31, 2009 was
$2.4 million, a $2.4 million decrease from the year ended December 31,
2008. The decrease is attributable to the impact of lower average
prices totaling $2.8 million, partially offset by an increase in sales volumes
totaling $0.4 million.
Oil sales
volumes were 5 thousand barrels during the year ended December 31, 2009 as
compared to 6 thousand barrels during the year ended December 31,
2008. The Fund’s oil prices averaged $56 per barrel and $94 per
barrel during the years ended December 31, 2009 and 2008,
respectively.
Gas sales
volumes were 493 thousand mcf during the year ended December 31, 2009 compared
to 438 thousand mcf during the year ended December 31, 2008. The
Fund’s gas prices averaged $4.20 per mcf and $9.59 during the years ended
December 31, 2009 and 2008, respectively.
The
decrease in oil volumes for the year ended December 31, 2009 compared to the
year ended December 31, 2008 was due to lower production rates for East Cameron
299, West Cameron 556, West Cameron 76 A-1 and West Delta 68, partially offset
by the onset of production of South Marsh Island 111.
The
increase in gas volumes for the year ended December 31, 2009 compared to the
year ended December 31, 2008 was primarily attributable to the onset of
production of West Delta 67, West Delta 68, Vermilion 344 and South Marsh Island
111, partially offset by a decrease in production rates for East Cameron 299,
West Cameron 556 and West Cameron 76 A-1.
Depletion and
Amortization. Depletion and amortization for the year ended December 31,
2009 was $2.9 million, a $0.5 million increase from the year ended December 31,
2008. The increase resulted from an increase in production volumes
totaling $0.3 million coupled with an increase in average depletion rates
totaling $0.3 million. The increase in depletion rates was the result
of higher cost reserve additions, principally attributable to Vermilion 344 and
South Marsh Island 111, partially offset by decreased rates for East Cameron 299
and West Cameron 556, attributable to the impairment charges taken for those
wells.
Impairment of
Proved Properties. During the years ended December 31, 2009
and 2008, the Fund recorded impairments of proved properties of $2.4 million and
$0.6 million, respectively. During the year ended December 31, 2009,
impairments of $1.9 million, relating to East Cameron 299 and West Cameron 556
were attributable to lower oil and gas commodity prices and revisions to reserve
estimates. The impairments to Vermilion 344 of $0.5 million were attributable to lower oil and gas commodity prices,
a reduction in the Fund’s estimates of proved oil and gas reserves, and the
year-end determination that the well was fully
depleted. During the year ended December 31, 2008, the impairment to
Vermilion 344 of $0.6 million was attributable to
increased project costs, lower oil and gas commodity prices and a reduction in
the Fund’s estimates of proved oil and gas reserves.
Operating
Expenses. Operating expenses include the costs of operating
and maintaining wells and related facilities, accretion expense related to asset
retirement obligations, and dry-hole costs, as detailed in the following
table.
Year
ended December 31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Lease
operating expense
|
$ | 621 | $ | 481 | ||||
Accretion
expense
|
8 | 5 | ||||||
Dry-hole
costs, net
|
(16 | ) | (18 | ) | ||||
$ | 613 | $ | 468 |
Lease
operating expense for the years ended December 31, 2009 and 2008 related to the
Fund’s producing properties during each period as outlined above in
“Overview”. For the year ended December
31, 2009, the average production cost was $1.15 per mcfe compared to $0.97 per
mcfe for the year ended December 31, 2008. Accretion expense is related
to the asset retirement obligations established for the Fund’s proved
properties. 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.
General and
Administrative Expenses. General and
administrative expenses represent costs specifically identifiable or
allocable to the Fund, as detailed in the
following table.
Year
ended December 31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Accounting
fees
|
$ | 131 | $ | 153 | ||||
Management
reimbursement and other
|
81 | 85 | ||||||
Insurance
expense
|
61 | 58 | ||||||
$ | 273 | $ | 296 |
Accounting
fees represent audit and tax preparation fees, quarterly reviews and filing fees
incurred by the Fund. Management reimbursement and other expenses
relate to reimbursements for various administrative costs incurred on the Fund’s
behalf. 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.
Interest
Income. Interest income is comprised of interest earned on money
market accounts and investments in U.S. Treasury securities within the Fund’s
salvage fund. Interest income for the year ended December 31, 2009
was $44 thousand, a $0.1 million decrease from the year ended December 31,
2008. The decrease was the result of a reduction in average
outstanding balances earning interest due to ongoing capital expenditures for
oil and gas properties coupled with lower interest rates earned.
Capital
Resources and Liquidity
Operating
Cash Flows
Cash
flows provided by operating activities for the year ended December 31, 2009 were
$1.9 million, primarily related to revenue receipts of $2.6 million, $0.1
million received as a refund of estimated royalty payments made in 2008 and
favorable working capital of $0.1 million. These cash receipts were
partially offset by operating expenses of $0.6 million and general and
administrative expenses of $0.3 million.
Cash
flows provided by operating activities for the year ended December 31, 2008 were
$4.2 million, primarily related to revenue receipts of $5.0 million and interest
income received of $0.1 million. These cash receipts were partially
offset by operating expenses of $0.5 million, general and administrative
expenses of $0.3 million and estimated royalty payments of $0.1
million.
Investing
Cash Flows
Cash
flows used in investing activities for the year ended December 31, 2009 were
$0.3 million, primarily related to capital expenditures for oil and gas
properties.
Cash
flows used in investing activities for the year ended December 31, 2008 were
$2.7 million, primarily related to capital expenditures for oil and gas
properties.
Financing
Cash Flows
Cash
flows used in financing activities for the year ended December 31, 2009 were
$2.1 million, related to shareholder distributions.
Cash
flows used in financing activities for the year ended December 31, 2008 were
$3.8 million, related to shareholder distributions.
Estimated
Capital Expenditures
The Fund
has entered into multiple agreements for the drilling and development of its
investment properties. The estimated capital expenditures associated
with these agreements can vary depending on the stage of development on a
property-by-property basis. As of December 31, 2009, the Fund had
committed to spend an additional $0.3 million related to its investment
properties.
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 and capital
expenditures for its investment properties. Operations are funded
utilizing operating income, existing cash on-hand and income earned
therefrom.
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
subject to available cash from operations, reserve requirements and the Fund’s
operations.
Off-Balance
Sheet Arrangements
The Fund
had no off-balance sheet arrangements at December 31, 2009 and 2008 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 contracts. No contractual obligations exist at
December 31, 2009 and 2008 other than those discussed in “Estimated Capital
Expenditures” above.
Recent
Accounting Pronouncements
See Note
3 of Notes to Financial Statements – “Recent Accounting Standards” in Item 8.
“Financial Statements and Supplementary Data” contained in this Annual Report
for a discussion of recent accounting pronouncements.
Not
required.
All
financial statements meeting the requirements of Regulation S-X and the
supplementary financial information required by Item 302 of Regulation S-K are
included in the financial statements listed in Item 15. “Exhibits, Financial
Statement Schedules” and filed as part of this report.
None.
Disclosure
Controls and Procedures
Under the
supervision and with the participation of the Chief Executive Officer and Chief
Financial Officer of the Fund, management of the Fund and the Manager carried
out an evaluation of the effectiveness of the design and operation of the Fund’s
disclosure controls and procedures as defined in the Exchange Act Rule 13a-15(e)
as of December 31, 2009. Based upon the evaluation, the Chief
Executive Officer and Chief Financial Officer concluded that the Fund’s
disclosure controls and procedures are effective as of the end of the period
covered by this report.
Management's
Report on Internal Control over Financial Reporting
Management
of the Fund is responsible for establishing and maintaining adequate internal
control over financial reporting (as defined in Exchange Act Rule 13a-15(f)).
The Fund’s internal control over financial reporting is designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect all misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may
deteriorate.
Management
of the Fund, including its Chief Executive Officer and Chief Financial Officer,
assessed the effectiveness of the Fund’s internal control over financial
reporting as of December 31, 2009. In making this assessment,
management of the Fund used the criteria set forth by the Committee of
Sponsoring Organizations of the Treadway Commission (the “COSO”) in Internal
Control — Integrated Framework. Based on their
assessment using those criteria, management of the Fund concluded that, as of
December 31, 2009, the Fund’s internal control over financial reporting is
effective.
This
Annual Report does not include an attestation report of the Fund’s registered
public accounting firm regarding internal control over financial reporting.
Management’s report was not subject to attestation by the Fund’s registered
public accounting firm pursuant to temporary rules of the Securities and
Exchange Commission that permit the Fund to provide only management’s report in
this Annual Report.
Changes
in Internal Control over Financial Reporting
The Chief
Executive Officer and Chief Financial Officer of the Fund have concluded that
there have not been any changes in the Fund’s internal control over financial
reporting during the quarter ended December 31, 2009 that have materially
affected, or are reasonably likely to materially affect, the Fund’s internal
control over financial reporting.
None.
PART
III
The Fund
has engaged Ridgewood Energy as the Manager. The Manager has very broad
authority, including the authority to appoint the executive officers of the
Fund. Executive officers of Ridgewood Energy and the Fund and their
ages at December 31, 2009 are as follows:
Officer
of
|
|||
Ridgewood
Energy
|
|||
Name, Age and Position with
Registrant
|
Corporation Since
|
||
Robert
E. Swanson, 62
|
|||
Chief
Executive Officer
|
1982
|
||
Kenneth
W. Lang, 55
|
|||
President
and Chief Operating Officer
|
2009
|
||
Kathleen
P. McSherry, 44
|
|||
Executive
Vice President and
|
|||
Chief
Financial Officer
|
2001
|
||
Robert
L. Gold, 51
|
|||
Executive
Vice President
|
1987
|
||
Daniel
V. Gulino, 49
|
|||
Senior
Vice President and General Counsel
|
|
2003
|
The
officers in the above table have also been officers of the Fund since March 1,
2004, the date of inception of the Fund, with the exception of Mr. Lang who has
been an officer of Ridgewood Energy and the Fund since June 2009. The
officers are employed by and paid exclusively by the Manager. Set
forth below is certain biographical information regarding the executive officers
of Ridgewood Energy and the Fund:
Robert E. Swanson has served
as the Chairman, Chief Executive Officer and controlling shareholder of
Ridgewood Energy since its inception and is the Chairman of the Investment
Committee. Mr. Swanson is also the Chairman of Ridgewood Renewable
Power, LLC and Ridgewood Capital Management, LLC and President of Ridgewood
Securities Corporation, affiliates of Ridgewood Energy. Mr. Swanson is a member
of the New York State and New Jersey State Bars, the Association of the Bar of
the City of New York and the New York State Bar Association. He is a graduate of
Amherst College and Fordham University Law School.
Kenneth W. Lang has served as
the President and Chief Operating Officer of Ridgewood Energy since June 2009
and is a member of the Investment Committee. Prior to joining the
Fund, Mr. Lang was with BP for twenty-four years, ultimately serving as Senior
Vice President for BP’s Gulf of Mexico business and a member of the Board of
Directors for BP America, Inc. Mr. Lang is a graduate of the
University of Houston.
Kathleen P. McSherry has
served as the Executive Vice President and Chief Financial Officer of Ridgewood
Energy since 2001 and is a member of the Investment Committee. Ms. McSherry also
serves as Vice President of Systems and Administration of Ridgewood Power. Ms.
McSherry holds a Bachelor of Science degree in Accounting.
Robert L. Gold has served as
the Executive Vice President of Ridgewood Energy since 1987 and is a member of
the Investment Committee. Mr. Gold has also served as the President and Chief
Executive Officer of Ridgewood Capital since its inception in 1998. Mr. Gold is
a member of the New York State Bar. Mr. Gold is a graduate of Colgate University
and New York University School of Law.
Daniel V. Gulino has served as
Senior Vice President and General Counsel of Ridgewood Energy since 2003. Mr.
Gulino also serves as Senior Vice President and General Counsel of Ridgewood
Renewable Power, Ridgewood Capital Management and Ridgewood Securities
Corporation. Mr. Gulino is a member of the New Jersey State and
Pennsylvania State Bars. Mr. Gulino is a graduate of Fairleigh Dickinson
University and Rutgers School of Law.
Board
of Directors and Board Committees
The Fund
does not have its own board of directors or any board committees. The Fund
relies upon the Manager to provide recommendations regarding dispositions and
financial disclosure. Officers of the Fund are not compensated by the
Fund, and all compensation matters are addressed by the Manager, as described in
Item 11. “Executive Compensation” of this Annual Report. Because the Fund
does not maintain a board of directors and because officers of the Fund are
compensated by the Manager, the Manager believes that it is appropriate for the
Fund to not have a nominating or compensation committee.
Code
of Ethics
The
Manager of the Fund has adopted a code of ethics for all employees, including
the Manager’s principal executive officer and principal financial and accounting
officer. If any amendments are made to the code of ethics or the Manager of the
Fund grants any waiver, including any implicit waiver, from a provision of the
code to any of the Manager’s executive officers, the Fund will disclose the
nature of such amendment or waiver on our website or in a current report on Form
8-K. Copies of the code of ethics are available, without charge, on
the Manager’s website at www.ridgewoodenergy.com and in print upon written
request to the business address of the Manager at 14 Philips Parkway, Montvale,
New Jersey 07645, ATTN: General Counsel.
Section
16(a) Beneficial Ownership Reporting Compliance
Section
16(a) of the Exchange Act, as amended, requires the Fund’s executive officers
and directors, and persons who own more than 10% of a registered class of the
Fund’s equity securities, to file reports of ownership and changes in ownership
with the SEC. Based on a review of the copies of reports furnished or otherwise
available to the Fund, the Fund believes that during the year ended December 31,
2009, all filing requirements applicable to its officers, directors and 10%
beneficial owners were met.
The
executive officers of the Fund do not receive compensation from the Fund. The
Manager, or its affiliates, compensates the officers without additional payments
by the Fund. See Item 13. “Certain Relationships and Related Transactions, and
Director Independence” for more information regarding Manager compensation and
payments to affiliated entities.
The
following table sets forth information with respect to beneficial ownership of
the shares as of March 23, 2010 (no person owns more than 5% of the shares)
by:
|
•
|
each
executive officer (there are no directors);
and
|
|
•
|
all
of the executive officers as a
group.
|
Beneficial
ownership is determined in accordance with the rules of the SEC and includes
voting or investment power with respect to the securities. Except as indicated
by footnote, and subject to applicable community property laws, the persons
named in the table below have sole voting and investment power with respect to
all shares shown as beneficially owned by them. Percentage of beneficial
ownership is based on 480.7046 shares outstanding at March 23, 2010. Other than
as indicated below, no officer of the Manager or the Fund owns any of the
Shares.
Name of beneficial owner
|
Number
of shares
|
Percent
|
||||||
Robert
E. Swanson, Chief Executive Officer (1)
|
0.6667 | * | ||||||
Executive
officers as a group (1)
|
0.6667 | * |
*
Represents less than one percent.
(1)
Includes shares owned by Mr. Swanson’s family members and trusts, which he
controls.
In
accordance with the LLC Agreement the Manager is entitled to an annual
management fee equal to 2.5% of the total shareholder capital. During 2005, the
Manager waived its management fee for the remaining life of the
Fund. Upon the waiver of the management fee, the Fund began
recording costs relating to services provided by the Manager for accounting and
investor relations. Such costs totaled $80 thousand for each of the
years ended December 31, 2009 and 2008, which were included in general and
administrative expenses.
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. See the discussion under the heading “Properties” in Item 1.
“Business”.
Profits
and losses are allocated in accordance with the LLC Agreement. In
general, profits and losses in any year are allocated 85% to shareholders and
15% to the Manager. The primary exception to this treatment is that
all items of expense, loss, deduction and credit attributable to the expenditure
of shareholders’ capital contributions are allocated 99% to shareholders and 1%
to the Manager.
The
following table presents fees for services rendered by Deloitte & Touche LLP
for the years ended December 31, 2009 and 2008.
Year
ended December 31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Audit
fees (1)
|
$ | 105 | $ | 105 | ||||
Audit-related
fees
(2)
|
3 | - | ||||||
$ | 108 | $ | 105 |
(1)
|
Fees
for audit of annual financial statements, reviews of the related quarterly
financial statements, and reviews of documents filed with the
SEC.
|
(2)
|
Fees
for consultations regarding the Fund’s disclosure controls and procedures
in accordance with Section 906 of the Sarbanes-Oxley Act of
2002.
|
PART
IV
(a)
(1)
|
Financial
Statements
|
See
“Index to Financial Statements” set forth on page F-1.
(a)
(2)
|
Financial
Statement Schedules
|
None.
(a)
(3)
Exhibit
|
||||
Number
|
Title of Exhibit
|
Method of Filing
|
||
3.1
|
Articles
of Formation of Ridgewood Energy K Fund LLC dated March 1,
2004
|
Incorporated
by reference to the Fund's Form 10 filed on April 29,
2005
|
||
3.2
|
Limited
Liability Company Agreement between Ridgewood Energy Corporation and
Investors of Ridgewood Energy K Fund LLC dated April 1,
2004
|
Incorporated
by reference to the Fund's Form 10 filed on April 29,
2005
|
||
31.1
|
Certification
of Robert E. Swanson, Chief Executive Officer of the Fund, pursuant to
Securities Exchange Act Rule 13a-14(a)
|
Filed
herewith
|
||
31.2
|
Certification
of Kathleen P. McSherry, Executive Vice President and Chief Financial
Officer of the Fund, pursuant to Securities Exchange Act Rule
13a-14(a)
|
Filed
herewith
|
||
32
|
Certifications
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of
The Sarbanes-Oxley Act of 2002, signed by Robert E. Swanson, Chief
Executive Officer of the Fund and Kathleen P. McSherry, Executive Vice
President and Chief Financial Officer of the Fund
|
Filed
herewith
|
||
99
|
Report
of Ryder Scott Company, L.P.
|
Filed
herewith
|
INDEX
TO FINANCIAL STATEMENTS
|
PAGE
|
F-2
|
|
F-3
|
|
F-4
|
|
F-5
|
|
F-6
|
|
F-7
|
|
F-12
|
To the
shareholders and Manager of Ridgewood Energy K Fund, LLC:
We have
audited the accompanying balance sheets of Ridgewood Energy K Fund, LLC (the
“Fund”) as of December 31, 2009 and 2008, and the related statements of
operations, changes in members’ capital, and cash flows for the years ended
December 31, 2009 and 2008. These financial statements are the
responsibility of the Fund’s management. Our responsibility is to
express an opinion on these financial statements based on our
audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable assurance about whether
the financial statements are free of material misstatement. The Fund
is not required to have, nor were we engaged to perform, an audit of its
internal control over financial reporting. Our audits included
consideration of internal control over financial reporting as a basis for
designing audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the Fund’s
internal control over financial reporting. Accordingly, we express no
such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
In our
opinion, such financial statements present fairly, in all material respects, the
financial position of Ridgewood Energy K Fund, LLC as of December 31, 2009 and
2008, and the results of its operations and its cash flows for the years ended
December 31, 2009 and 2008, in conformity with accounting principles generally
accepted in the United States of America.
As
discussed in Note 3 to the financial statements, the Fund adopted the reserve
estimation and disclosure requirements of Extractive Activities – Oil and
Gas as of December 31, 2009.
/s/ Deloitte & Touche
LLP
Parsippany,
New Jersey
March 23,
2010
BALANCE
SHEETS
(in
thousands, except share data)
December
31,
|
||||||||
2009
|
2008
|
|||||||
ASSETS
|
||||||||
Current
assets:
|
||||||||
Cash
and cash equivalents
|
$ | 2,786 | $ | 3,295 | ||||
Production
receivable
|
209 | 422 | ||||||
Other
current assets
|
25 | 185 | ||||||
Total
current assets
|
3,020 | 3,902 | ||||||
Salvage
fund
|
1,189 | 1,162 | ||||||
Oil
and gas properties:
|
||||||||
Unproved
properties
|
- | 807 | ||||||
Proved
properties
|
21,972 | 22,216 | ||||||
Less: accumulated
depletion and amortization
|
(16,795 | ) | (12,904 | ) | ||||
Total
oil and gas properties, net
|
5,177 | 10,119 | ||||||
Total
assets
|
$ | 9,386 | $ | 15,183 | ||||
LIABILITIES
AND MEMBERS' CAPITAL
|
||||||||
Current
liabilities:
|
||||||||
Due
to operators
|
$ | 156 | $ | 245 | ||||
Accrued
expenses
|
65 | 46 | ||||||
Total
current liabilities
|
221 | 291 | ||||||
Asset
retirement obligations
|
478 | 348 | ||||||
Total
liabilities
|
699 | 639 | ||||||
Commitments
and contingencies (Note 8)
|
||||||||
Members'
capital:
|
||||||||
Manager:
|
||||||||
Distributions
|
(290 | ) | (290 | ) | ||||
Retained
earnings
|
1,153 | 982 | ||||||
Manager's
total
|
863 | 692 | ||||||
Shareholders:
|
||||||||
Capital
contributions (534 shares authorized;
480.7046
issued and outstanding)
|
70,860 | 70,860 | ||||||
Syndication
costs
|
(7,775 | ) | (7,775 | ) | ||||
Distributions
|
(11,998 | ) | (9,887 | ) | ||||
Accumulated
deficit
|
(43,263 | ) | (39,346 | ) | ||||
Shareholders'
total
|
7,824 | 13,852 | ||||||
Total
members' capital
|
8,687 | 14,544 | ||||||
Total
liabilities and members' capital
|
$ | 9,386 | $ | 15,183 |
The
accompanying notes are an integral part of these financial
statements.
STATEMENTS
OF OPERATIONS
(in
thousands, except per share data)
Year
ended December 31,
|
||||||||
2009
|
2008
|
|||||||
Revenue
|
||||||||
Oil
and gas revenue
|
$ | 2,385 | $ | 4,810 | ||||
Expenses
|
||||||||
Depletion
and amortization
|
2,895 | 2,357 | ||||||
Impairment
of proved properties
|
2,394 | 568 | ||||||
Operating
expenses
|
613 | 468 | ||||||
General
and administrative expenses
|
273 | 296 | ||||||
Total
expenses
|
6,175 | 3,689 | ||||||
(Loss)
income from operations
|
(3,790 | ) | 1,121 | |||||
Other
income
|
||||||||
Interest
income
|
44 | 137 | ||||||
Net
(loss) income
|
$ | (3,746 | ) | $ | 1,258 | |||
Manager
Interest
|
||||||||
Net
income
|
$ | 171 | $ | 578 | ||||
Shareholder
Interest
|
||||||||
Net
(loss) income
|
$ | (3,917 | ) | $ | 680 | |||
Net
(loss) income per share
|
$ | (8,148 | ) | $ | 1,415 |
The
accompanying notes are an integral part of these financial
statements.
STATEMENTS
OF CHANGES IN MEMBERS’ CAPITAL
(in
thousands, except share data)
#
of Shares
|
Manager
|
Shareholders
|
Total
|
|||||||||||||
Balances,
December 31, 2007
|
480.7046 | $ | 114 | $ | 16,985 | $ | 17,099 | |||||||||
Net
income
|
- | 578 | 680 | 1,258 | ||||||||||||
Distributions
|
- | - | (3,813 | ) | (3,813 | ) | ||||||||||
Balances,
December 31, 2008
|
480.7046 | 692 | 13,852 | 14,544 | ||||||||||||
Net
income (loss)
|
- | 171 | (3,917 | ) | (3,746 | ) | ||||||||||
Distributions
|
- | - | (2,111 | ) | (2,111 | ) | ||||||||||
Balances,
December 31, 2009
|
480.7046 | $ | 863 | $ | 7,824 | $ | 8,687 |
The
accompanying notes are an integral part of these financial
statements.
STATEMENTS
OF CASH FLOWS
(in
thousands)
Year
ended December 31,
|
||||||||
2009
|
2008
|
|||||||
Cash
flows from operating activities
|
||||||||
Net
(loss) income
|
$ | (3,746 | ) | $ | 1,258 | |||
Adjustments
to reconcile net (loss) income to net cash
|
||||||||
provided
by operating activities:
|
||||||||
Depletion
and amortization
|
2,895 | 2,357 | ||||||
Dry-hole
costs
|
(16 | ) | (18 | ) | ||||
Impairment
of proved properties
|
2,394 | 568 | ||||||
Accretion
expense
|
8 | 5 | ||||||
Changes
in assets and liabilities:
|
||||||||
Decrease
in production receivable
|
213 | 173 | ||||||
Decrease
(increase) in other current assets
|
160 | (135 | ) | |||||
Increase
in due to operators
|
5 | 23 | ||||||
Decrease
in accrued expenses
|
(8 | ) | (23 | ) | ||||
Net
cash provided by operating activities
|
1,905 | 4,208 | ||||||
Cash
flows from investing activities
|
||||||||
Capital
expenditures for oil and gas properties
|
(276 | ) | (2,695 | ) | ||||
Interest
reinvested in salvage fund
|
(27 | ) | (29 | ) | ||||
Net
cash used in investing activities
|
(303 | ) | (2,724 | ) | ||||
Cash
flows from financing activities
|
||||||||
Distributions
|
(2,111 | ) | (3,813 | ) | ||||
Net
cash used in financing activities
|
(2,111 | ) | (3,813 | ) | ||||
Net
decrease in cash and cash equivalents
|
(509 | ) | (2,329 | ) | ||||
Cash
and cash equivalents, beginning of year
|
3,295 | 5,624 | ||||||
Cash
and cash equivalents, end of year
|
$ | 2,786 | $ | 3,295 |
The
accompanying notes are an integral part of these financial
statements.
NOTES
TO FINANCIAL STATEMENTS
1. Organization
and Purpose
The
Ridgewood Energy K Fund, LLC (the “Fund”), a Delaware limited liability company,
was formed on March 1, 2004 and operates pursuant to a limited liability company
agreement (the “LLC Agreement”) dated April 1, 2004 by and among Ridgewood
Energy Corporation (the “Manager”) and the shareholders of the
Fund. The Fund was organized to acquire interests in oil and gas
properties located in the United States offshore waters of Texas, Louisiana and
Alabama in the Gulf of Mexico.
The
Manager has direct and exclusive control over the management of the Fund’s
operations. With respect to project investments, the Manager locates
potential projects, conducts due diligence and negotiates and completes the
transactions in which the investments are made. The Manager performs,
or arranges for the performance of, the management, advisory and administrative
services required for Fund operations. Such services include, without
limitation, the administration of shareholder accounts, shareholder relations
and the preparation, review and dissemination of tax and other financial
information. In addition, the Manager provides office space,
equipment and facilities and other services necessary for Fund
operations. The Manager also engages and manages the contractual
relations with unaffiliated custodians, depositories, accountants, attorneys,
broker-dealers, corporate fiduciaries, insurers, banks and others as
required. See Notes 2, 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 (“GAAP”) requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities as of the date
of the financial statements and the reported amounts of revenue and expense
during the reporting period. On an ongoing basis, the Manager reviews its
estimates, including those related to property balances, determination of proved
reserves, impairments and asset retirement obligations. Actual
results may differ from those estimates.
Cash
and Cash Equivalents
All
highly liquid investments with maturities when purchased of three months or less
are considered cash and cash equivalents. At times, bank deposits may be in
excess of federally insured limits. Effective January 1, 2010, the federally
insured limits of the Fund’s deposits are $250 thousand per insured financial
institution. Based upon these limits, at December 31, 2009, the
Fund’s bank balances would have exceeded federally insured limits by $2.5
million, of which $2.4 million was invested in money market accounts that invest
solely in U.S. Treasury bills and notes.
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
December 31, 2009, 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. 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.
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
December 31, 2009 and 2008, amounts recorded in due to operators totaling $0.1
million and $0.2 million, respectively, related to capital expenditures for oil
and gas properties.
Advances
to Operators for Working Interests and Expenditures
The
Fund’s acquisition of a working interest in a well or a project requires it to
make a payment to the seller for the Fund’s right, title and interest. The Fund
may be required to advance its share of estimated cash expenditures for the
succeeding month’s operation. The Fund accounts for such payments as advances to
operators for working interests and expenditures. As drilling costs are
incurred, the advances are reclassified to unproved properties.
Asset
Retirement Obligations
For oil
and gas properties, there are obligations to perform removal and remediation
activities when the properties are retired. When a project reaches drilling
depth and is determined to be either proved or dry, an asset retirement
obligation is incurred. Plug and abandonment costs associated with unsuccessful
projects are expensed as dry-hole costs. The following table presents
changes in asset retirement obligations for the years ended December 31, 2009
and 2008.
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Balance,
beginning of year
|
$ | 348 | $ | 81 | ||||
Liabilities
incurred
|
122 | 183 | ||||||
Liabilities
settled
|
- | - | ||||||
Accretion
expense
|
8 | 5 | ||||||
Revision
to prior estimate
|
- | 79 | ||||||
Balance,
end of year
|
$ | 478 | $ | 348 |
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 natural gas is sold to a purchaser
at a fixed or determinable price, when delivery has occurred and title has
transferred, and if collectibility of the revenue is probable.
The Fund
uses the sales method of accounting for gas production imbalances. The volumes
of gas sold may differ from the volumes to which the Fund is entitled based on
its interests in the properties. These differences create imbalances that are
recognized as a liability only when the properties’ estimated remaining reserves
net to the Fund will not be sufficient to enable the underproduced owner to
recoup its entitled share through production. The Fund’s recorded liability, if
any, would be reflected in other liabilities. No receivables are recorded for
those wells where the Fund has taken less than its share of
production.
Impairment
of Long-Lived Assets
The Fund
reviews the value of its oil and gas properties whenever management determines
that events and circumstances indicate that the recorded carrying value of
properties may not be recoverable. Impairments of producing
properties are determined by comparing future net undiscounted cash flows to the
net book value at the 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.
During
the year ended December 31, 2009, the Fund recorded impairments to its proved
properties totaling $2.4 million, resulting from the determination
that one of the Fund’s wells was fully depleted, lower oil and gas commodity
prices and revisions to reserve estimates. During the year ended
December 31, 2008, the Fund recorded impairments to proved properties totaling
$0.6 million, attributable to increased project
costs, lower oil and gas commodity prices and a reduction in the Fund’s
estimates of proved oil and gas reserves. The fair value of
the impaired wells was determined based on level 3 inputs, which include
projected income from proved and probable reserves utilizing forward price
curves, net of anticipated costs, discounted.
Depletion
and Amortization
Depletion
and amortization of the cost of proved oil and gas properties are calculated
using the units-of-production method. Proved developed reserves are
used as the base for depleting capitalized costs associated with successful
exploratory well costs. The sum of proved developed and proved
undeveloped reserves is used as the base for depleting or amortizing leasehold
acquisition costs, the costs to acquire proved properties and platform and
pipeline costs.
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 is effective for the first reporting period beginning after
December 15, 2009, which will be effective for the Fund beginning January 1,
2010. The Level 3 reconciliation disclosures are effective for fiscal
years beginning after December 15, 2010, which will be effective for the Fund
December 31, 2011. The adoption of the guidance is not expected to have a
material impact on Fund’s financial statements.
In
June 2009, the FASB issued Accounting Standards Codification as the source
of GAAP to be applied to nongovernmental agencies. This guidance explicitly
recognizes rules and interpretive releases of the SEC under authority of federal
securities laws as authoritative GAAP for SEC registrants. It was effective for
interim or annual periods ending after September 15, 2009. The guidance
was adopted for the third quarter 2009 and did not have a material impact on the
Fund’s financial statements.
In
May 2009, the FASB issued guidance on subsequent events, which sets forth
general standards of accounting for and disclosure of events that occur after
the balance sheet date but before financial statements are issued or are
available to be issued. The guidance was adopted effective for the second
quarter 2009 and did not have a material impact on the Fund’s financial
statements.
In
April 2009, the FASB issued guidance on interim disclosures about fair
value of financial instruments, which requires quarterly disclosure of
information about the fair value of financial instruments. The guidance
was adopted effective for the second quarter 2009 and did not have a material
impact on the Fund’s financial statements.
In April
2009, the FASB issued guidance on the recognition and presentation of
other-than-temporary impairments, which amends the other-than-temporary
impairment guidance for debt securities to make the guidance more operational
and to improve the presentation and disclosure of other-than-temporary
impairments on debt and equity securities in the financial statements. This
guidance does not amend existing recognition and measurement guidance related to
other-than-temporary impairments of equity securities. This guidance does not
require disclosures for earlier periods presented for comparative purposes at
initial adoption. In periods after initial adoption, this guidance requires
comparative disclosures only for periods ending after initial adoption. The
guidance was adopted effective for the second quarter 2009 and did not have a
material impact on the Fund’s financial statements.
In
September 2006, the FASB issued guidance related to fair value measurements.
This guidance 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 FASB also issued guidance on the methods used
to measure fair value and required expanded disclosures related to fair value
measurements. The Fund adopted this guidance for financial assets and financial
liabilities effective January 1, 2008 and for non-financial assets and
non-financial liabilities effective January 1, 2009. The adoption did not
have a material impact on the Fund’s financial statements.
In
December 2008, the SEC issued Release No. 33-8995, “Modernization of
Oil and Gas Reporting” (“Release No. 33-8995”), amending oil and gas reporting
requirements under Rule 4-10 of Regulation S-X and Industry Guide 2 in
Regulation S-K. The new requirements provide for consideration of new
technologies in evaluating reserves, allow companies to disclose their probable
and possible reserves to investors, report oil and gas reserves using an average
price based on the prior 12-month period rather than year-end prices, and revise
the disclosure requirements for oil and gas operations. The final rules
were effective for fiscal years ending on or after
December 31, 2009. In January 2010, the FASB issued
guidance on oil and gas reserve estimation and disclosures to align the
Accounting Standards Codification with the disclosure requirements of Release
No. 33-8995. The FASB and SEC guidance has been adopted for the year ended
December 31, 2009.
In the unaudited supplementary financial information, the 2009
future estimated cash inflows are determined on average price based on the prior
12-month period whereby 2008 future estimated cash inflows are determined based
on year-end prices.
4. Unproved
Properties - Capitalized Exploratory Well Costs
Leasehold
acquisition and exploratory drilling costs are capitalized pending determination
of whether the well has found proved reserves. Unproved properties
are assessed on a quarterly basis by evaluating and monitoring if sufficient
progress is made on assessing the reserves. At December 31, 2009, the
Fund had no unproved properties. The following table reflects the net
changes in unproved properties for the years ended December 31, 2009 and
2008.
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Balance,
beginning of year
|
$ | 807 | $ | 1,869 | ||||
Additions
to capitalized exploratory well costs
pending
the determination of proved reserves
|
234 | 1,230 | ||||||
Reclassification
to proved properties based on
the
determination of proved reserves
|
(1,041 | ) | (2,292 | ) | ||||
Capitalized
exploratory well costs charged to
dry-hole
costs
|
- | - | ||||||
Balance,
end of year
|
$ | - | $ | 807 |
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. During the years ended December 31, 2009 and 2008, the Fund
recorded net dry-hole credits of $16 thousand and $18 thousand, respectively,
which are included in the Fund’s Statements of Operations as Operating
Expenses.
5. 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.
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. During 2006, the Manager elected to waive its right to
distributions of available cash from operations for the remaining life of the
Fund.
6. Related
Parties
Effective
October 1, 2005 and continuing for the remaining life of the Fund, the Manager
elected to waive its management fee. Upon the waiver of the
management fee, the Fund began recording costs relating to services provided by
the Manager for accounting and investor relations. Such costs,
totaling $80 thousand for each of the years ended December 31, 2009 and 2008,
respectively, were included in general and administrative expenses.
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 gas projects with other entities that are likewise managed by the
Manager.
7. Fair
Value of Financial Instruments
At
December 31, 2009 and 2008, cash and cash equivalents, production receivable,
salvage fund and accrued expenses approximate fair value.
8. Commitments
and Contingencies
Capital
Commitments
The Fund
has entered into multiple agreements for the drilling and development of its
investment properties. The estimated capital expenditures associated with these
agreements vary depending on the stage of development on a property-by-property
basis. As of December 31, 2009, the Fund had committed to spend an additional
$0.3 million related to its investment properties.
Environmental
Considerations
The
exploration for and development of oil and natural gas involves the extraction,
production and transportation of materials which, under certain conditions, can
be hazardous or cause environmental pollution problems. The Manager and
operators of the Fund’s properties are continually taking action they believe
appropriate to satisfy applicable federal, state and local environmental
regulations and do not currently anticipate that compliance with federal, state
and local environmental regulations will have a material adverse effect upon
capital expenditures, results of operations or the competitive position of the
Fund in the oil and gas industry. However, due to the significant
public and governmental interest in environmental matters related to those
activities, the Manager cannot predict the effects of possible future
legislation, rule changes, or governmental or private claims. At
December 31, 2009 and 2008, there were no known environmental contingencies that
required the Fund to record a liability.
Insurance
Coverage
The Fund
is subject to all risks inherent in the exploration for and development of oil
and 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.
9. Subsequent
Events
The Fund
has assessed the impact of subsequent events through the date of issuance of its
financial statements, and has concluded that there were no such events that
require adjustment to, or disclosure in, the notes to the financial
statements.
Supplementary
Financial Information
Information
about Oil and Gas Producing Activities - Unaudited
In
accordance with the Financial Accounting Standards Board guidance on disclosures
of oil and gas producing activities, this section provides supplementary
information on oil and gas exploration and producing activities of the
Fund. The Fund is engaged solely in oil and gas activities, all of which
are currently located in the United States offshore waters of Louisiana in the
Gulf of Mexico.
Table
I - Capitalized Costs Relating to Oil and Gas Producing
Activities
December
31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Unproved
properties
|
$ | - | $ | 807 | ||||
Proved
properties
|
21,972 | 22,216 | ||||||
Total
oil and gas properties
|
21,972 | 23,023 | ||||||
Accumulated
depletion and amortization
|
(16,795 | ) | (12,904 | ) | ||||
Oil
and gas properties, net
|
$ | 5,177 | $ | 10,119 |
Table
II - Costs Incurred in Oil and Gas Property Acquisition, Exploration, and
Development
Year
ended December 31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Exploration
costs
|
$ | 253 | $ | 955 | ||||
Development
costs
|
52 | 934 | ||||||
$ | 305 | $ | 1,889 |
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. at December 31, 2009 and
2008. These reserve disclosures have been prepared in compliance with
the Securities and Exchange Commission rules and represent all reserves managed
by Ridgewood Energy Corporation, the Manager of the Fund. The
reserve data disclosed in the following tables represent the Fund's share of
such reserves based on the Fund's net revenue interest in each
property. Due to inherent uncertainties and the limited nature of
recovery data, estimates of reserve information are subject to change as
additional information becomes available.
December
31, 2009
|
December
31, 2008
|
||||||||||||||||
United
States
|
|||||||||||||||||
Oil
(BBLS)
|
Gas
(MCF)
|
Oil
(BBLS)
|
Gas
(MCF)
|
||||||||||||||
Proved
developed and undeveloped reserves:
|
|||||||||||||||||
Beginning
of year
|
49,675 | 1,689,276 | 38,482 | 2,508,424 | |||||||||||||
Extensions
and discoveries
|
1,507 | 358,714 | 23,374 | 222,093 | |||||||||||||
Revisions
of previous estimates (a)
|
(12,367 | ) | (567,434 | ) | (5,735 | ) | (603,601 | ) | |||||||||
Production
|
(4,960 | ) | (501,057 | ) | (6,446 | ) | (437,640 | ) | |||||||||
End
of year
|
33,855 | 979,499 | 49,675 | 1,689,276 | |||||||||||||
Proved
developed reserves:
|
|||||||||||||||||
Beginning
of year
|
39,490 | 1,096,603 | 35,223 | 2,377,243 | |||||||||||||
End
of year
|
33,455 | 899,437 | 39,490 | 1,096,603 | |||||||||||||
Proved
undeveloped reserves:
|
|||||||||||||||||
Beginning
of year
|
10,185 | 592,673 | 3,259 | 131,181 | |||||||||||||
End
of year
|
400 | 80,062 | 10,185 | 592,673 | |||||||||||||
(a) |
Revisions
of previous estimates are primarily attributable to the year-end
determination that one of the Fund's wells was fully depleted at December
31, 2009, coupled with revisions due to well
performance.
|
Table
IV - Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserve Quantities
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 gas reserves. At December 31, 2009, future cash inflows were
determined based on average prices for the prior twelve month
period. At December 31, 2008, future cash inflows were determined
based on year-end prices. Future production and development costs are
derived based on current costs assuming continuation of existing economic
conditions.
December
31,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Future
cash inflows
|
$ | 6,015 | $ | 12,328 | ||||
Future
production costs
|
(1,246 | ) | (1,675 | ) | ||||
Future
development costs
|
(808 | ) | (2,232 | ) | ||||
Future
net cash flows
|
3,961 | 8,421 | ||||||
10%
annual discount for estimated timing of cash flows
|
(735 | ) | (1,578 | ) | ||||
Standardized
measure of discounted future estimated net cash flows
|
$ | 3,226 | $ | 6,843 |
Table
V - Changes in the Standardized Measure for Discounted Cash Flows
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,
|
||||||||
2009
|
2008
|
|||||||
(in
thousands)
|
||||||||
Net
change in sales and transfer prices and in production costs
related
to future production
|
$ | (2,038 | ) | $ | (2,331 | ) | ||
Sales
and transfer of oil and gas produced during the period
|
(1,775 | ) | (4,349 | ) | ||||
Net
change due to extensions, discoveries, and improved
recovery
|
771 | 1,688 | ||||||
Changes
in estimated future development costs
|
1,803 | - | ||||||
Net
change due to revisions in quantity estimates
|
(2,610 | ) | (4,022 | ) | ||||
Accretion
of discount
|
684 | 1,448 | ||||||
Other
|
(452 | ) | (71 | ) | ||||
Aggregate
change in the standardized measure of discounted future net
cash
flows for the year
|
$ | (3,617 | ) | $ | (7,637 | ) |
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 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.
Pursuant
to the requirements of Section 13 or 15(d) 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 K FUND, LLC
|
||
Date:
March 23, 2010
|
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
23, 2010
|
Robert
E. Swanson
|
||
/s/
KATHLEEN P. MCSHERRY
|
Executive
Vice President and Chief Financial Officer (Principal Accounting
Officer)
|
March
23, 2010
|
Kathleen
P. McSherry
|
||
RIDGEWOOD
ENERGY CORPORATION
|
||
/s/
ROBERT E. SWANSON
|
Chief
Executive Officer of Manager
|
March
23, 2010
|
Robert
E. Swanson
|
||