Attached files
| file | filename |
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| EX-23.1 - EXHIBIT 23.1 - PDC 2004-B Limited Partnership | ex23_1.htm |
| EX-32.1 - EXHIBIT 32.1 - PDC 2004-B Limited Partnership | ex32_1.htm |
| EX-31.1 - EXHIBIT 31.1 - PDC 2004-B Limited Partnership | ex31_1.htm |
| EX-31.2 - EXHIBIT 31.2 - PDC 2004-B Limited Partnership | ex31_2.htm |
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
WASHINGTON,
DC 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, 2008
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
Commission
File Number 000-51219
PDC
2004-B Limited Partnership
(Exact
name of registrant as specified in its charter)
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West Virginia
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20-0547318
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(State
or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification
No.)
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1775 Sherman Street, Suite
3000, Denver, Colorado 80203
(Address
of principal executive offices) (Zip
code)
Registrant's
telephone number, including area code (303)
860-5800
Securities
registered pursuant to Section 12(b) of the Act: None
Securities
registered pursuant to Section 12(g) of the Act:
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Title
of Each Class
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Limited
Partnership Interests
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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 registrant is not required to file reports pursuant to Section
13 or Section 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 and (2) has been subject to such filing requirements for the
past 90 days.
Yes o No
x
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 (§ 229.405 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 disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of 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 definition of "large accelerated filer," "accelerated filer" and "smaller
reporting company" in Rule 12b-2 of the Exchange Act:
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Large
accelerated filer o
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Accelerated
filer o
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Non-accelerated
filer o
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Smaller
reporting company x
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Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No
x
State the
aggregate market value of the voting and non-voting common equity held by
non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of the
last business day of the registrant's most recently completed second fiscal
quarter:
There
is no trading market in the Partnership’s securities. Therefore,
there is no aggregate market value.
As of
September 30, 2009, the Partnership had 899.94 units of limited partnership
interest and no units of additional general partnership interest
outstanding.
PDC 2004-B LIMITED PARTNERSHIP
INDEX
TO REPORT ON FORM 10-K
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Page
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PART
I
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1
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Item
1
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2
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Item
1A
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13
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Item
1B
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21
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Item
2
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21
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Item
3
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22
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Item
4
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23
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PART
II
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Item
5
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23
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Item
6
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24
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Item
7
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24
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Item
7A
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38
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Item
8
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40
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Item
9
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40
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Item
9A(T)
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40
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Item
9B
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43
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PART
III
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Item
10
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44
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Item
11
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47
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Item
12
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48
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Item
13
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48
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Item
14
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49
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PART
IV
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Item
15
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49
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51
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F-1
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PART I
Explanatory
Note to Comprehensive Annual Report
PDC
2004-B Limited Partnership (the “Partnership” or the “Registrant”), which was
formed and funded on July 28, 2004 and, filed a Comprehensive Annual Report on
Form 10-K for the years ended December 31, 2007, 2006 and 2005 on August 5,
2009. The report included condensed quarterly unaudited financial
statements for each of the applicable quarters in 2007, 2006 and
2005.
This
Comprehensive Annual Report on Form 10-K for the years ended December 31, 2008
and 2007 is the first periodic report the Partnership has filed with the
Securities and Exchange Commission, or SEC, since the filing of the previously
mentioned Comprehensive Annual Report on Form 10-K for 2007-2005. The
financial information presented in this Annual Report on Form 10-K includes
audited financial statements for the years ended December 31, 2008 and 2007 as
well as unaudited condensed financial information for each applicable interim
period in 2008 and 2007.
Special
Note Regarding Forward Looking Statements
This
Annual Report contains forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the
Securities Exchange Act of 1934 (the “Exchange Act”) regarding PDC 2004-B
Limited Partnership’s (the “Partnership’s” or the “Registrant’s”) business,
financial condition, results of operations and prospects that are subject to
risks and uncertainties. Words such as “expects”, “anticipates”,
“intends”, “plans”, “believes”, “seeks”, “estimates” and similar expressions or
variations of such words are intended to identify forward-looking statements
herein, which include statements of estimated oil and natural gas production and
reserves, drilling plans, future cash flows, anticipated liquidity, anticipated
capital expenditures and the Managing General Partner’s Petroleum Development
Corporation’s (“MGP’s” or “PDC’s”) strategies, plans and
objectives. However, these are not the exclusive means of identifying
forward-looking statements herein. Although forward-looking
statements contained in this report reflect the Managing General Partner's good
faith judgment, such statements can only be based on facts and factors currently
known to them. Consequently, forward-looking statements are
inherently subject to risks and uncertainties, including risks and uncertainties
incidental to the development, production and marketing of natural gas and oil,
and actual outcomes may differ materially from the results and outcomes
discussed in the forward-looking statements. Important factors that could cause
actual results to differ materially from the forward looking statements include,
but are not limited to:
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·
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changes
in production volumes, worldwide demand, and commodity prices for oil and
natural gas;
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·
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risks
incident to the operation of natural gas and oil
wells;
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·
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future
production and development costs;
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·
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the
availability of sufficient pipeline and other transportation facilities to
carry Partnership production and the impact of these facilities on
price;
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·
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the
effect of existing and future laws, governmental regulations and the
political and economic climate of the United States of America (“U.S.”)
and the impact of the global
economy;
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·
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the
effect of natural gas and oil derivatives
activities;
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·
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availability
and cost of capital and conditions in the capital markets;
and
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·
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losses
possible from pending and/or future litigation and the costs incident
thereto.
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Further,
the Partnership urges the reader to carefully review and consider the cautionary
statements made in this report, including the risks and uncertainties that may
affect the Partnership's business as described herein under Item 1A, Risk Factors and its other
filings with the SEC and public disclosures. Readers are cautioned
not to place undue reliance on forward-looking statements, which speak only as
of the date of this report. The Partnership cautions you not to place
undue reliance on forward-looking statements, which speak only as of the date of
this report. The Partnership undertakes no obligation to update any
forward-looking statements in order to reflect any event or circumstance
occurring after the date of this report or currently unknown facts or conditions
or the occurrence of unanticipated events.
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Item 1.
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Business
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General
The
Partnership was organized as a limited partnership on July 28, 2004 under the
West Virginia Uniform Limited Partnership Act. Petroleum Development
Corporation, a Nevada Corporation, is the Managing General Partner of the
Partnership (hereafter, the “Managing General Partner”, “MGP” or
“PDC”). Upon completion of its public sale of its Partnership units
on July 28, 2004, the Partnership was funded and commenced its business
operations. The Partnership was funded with initial contributions of $18.0
million from 670 limited and additional general partners (collectively, the
“Investor Partners”) and a cash contribution of $4.0 million from the Managing
General Partner for its interest. After payment of syndication costs
of $1.8 million and a one-time management fee to the Managing General Partner of
$0.3 million, the Partnership had available cash of $19.9 million to commence
Partnership activities. Upon funding, the Partnership entered into a
Drilling and Operating Agreement (“D&O Agreement”) with the Managing General
Partner which governs the drilling and operational aspects of the
Partnership. The Partnership owns an undivided working interest in
natural gas and oil wells located in Colorado from which the Partnership
produces and sells natural gas and oil.
The
address and telephone number of the Partnership and PDC’s principal executive
offices, are 1775 Sherman Street, Suite 3000, Denver, Colorado 80203 and (303)
860-5800.
Drilling
Activities
The
Partnership commenced drilling activities immediately following funding on July
28, 2004. Drilling operations were completed in March 2005 when the
last of the Partnership’s 23 development wells were connected to sales and
gathering pipeline. The Partnership’s 23 gross wells represent 20.9
net wells, or the number of gross wells multiplied by the working interest in
the wells owned by the Partnership. All of the drilled wells are
located in Colorado and all wells drilled are completed and producing as of
December 31, 2008. The Partnership’s wells are considered
developmental wells. Therefore, no exploratory drilling activity was conducted
on behalf of the Partnership.
The 23
wells discussed above are the only wells to be drilled by the Partnership since
all of the funds raised in the Partnership offering have been
utilized. Accordingly, the Partnership’s business plan going forward
is to produce and sell the oil and gas from the Partnership’s wells, and to make
distributions to the partners as outlined in the Partnership’s cash distribution
policy, discussed in Item 5, Market for Registrant's Common
Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities.
In
accordance with the D&O Agreement, the Partnership paid its proportionate
share of the cost of drilling and completing each well as follows:
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a)
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The
cost of the prospect; and
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b)
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The
intangible well costs for each well completed and placed in production, an
amount equal to the depth of the well in feet at its deepest penetration
as recorded by the drilling contractor multiplied by the “intangible
drilling and completion cost” in the D&O Agreement, plus the actual
extra completion cost of zones completed in excess of the cost of the
first zone and actual additional costs incurred in the event that an
intermediate or third string of surface casing is run, rig mobilization
and trucking costs, the additional cost for directional drilling and drill
stem testing, sidetracking, fishing of drilling tools;
and
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c)
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The
tangible costs of drilling and completing the partnership wells and of
gathering pipelines necessary to connect the well to the nearest
appropriate sales point or delivery
point.
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Business
Segments
The
Partnership operates in one business segment, oil and natural gas
sales.
Plan of
Operations
With
regard to the Partnership’s developmental wells drilled in Colorado, 16 wells
were drilled in the Wattenberg Field and seven wells were drilled in the Grand
Valley Field.
The 16
Partnership wells in the Wattenberg Field were targeted to the Codell formation
or deeper. The Wattenberg Field, located north and east of Denver,
Colorado, is located within the Denver-Julesburg (DJ) Basin. Wells in
the DJ area may include as many as four productive formations. From
shallowest to deepest, these are the Sussex, the Niobrara, the Codell and the J
Sand. The primary producing zone for most of the Partnership’s wells
is the Codell formation, which produces a combination of natural gas and
oil.
The seven
Partnership wells in the Grand Valley Field are targeted to the Mesa Verde
formation. The Grand Valley Field is in the Piceance Basin, located near the
western border of Colorado. The producing interval consists of a
total of 150 to 300 feet of productive sandstone divided into 10 to 15 different
zones. The production zones are separated by layers of nonproductive
shale resulting in a total production interval of 2,000 to 4,000 feet with
alternating producing and non-producing zones. The natural gas
reserves and production are divided into these numerous smaller
zones.
The
typical well production profile for wells in both the Wattenberg and Grand
Valley fields displays an initial high production rate and relatively rapid
decline, followed by years of relatively shallow decline. Natural gas
is the primary hydrocarbon produced; however, the majority of the wells in the
Wattenberg Field also produce oil. For the natural gas, the purchase
price may include revenue from the recovery of propane and butane in the gas
stream, as well as a premium for the typical high-energy content of the natural
gas.
Generally,
PDC plans recompletion, as described below, of the wells producing from the
Codell formation in the Wattenberg Field wells after they have been in
production for five years or more, although the exact timing may be delayed or
accelerated due to changing commodity prices and the availability of additional
geological data and technology. The Managing General Partner has the
authority whether to recomplete the individual wells and to determine the timing
of any recompletions. The timing of the recompletions could be
affected by the desire to optimize the return to the Partnership by recompleting
the wells, when commodity prices are at levels to obtain the highest rate of
return. The number and timing of these recompletions will be subject
to Partnership’s cash availability since borrowing is not
permitted. A recompletion consists of a second fracture treatment in
the same formation originally fractured in the initial completion in well
bore. PDC and other producers have found that the recompletions
generally increase the production rate and recoverable reserves of the
wells. However, all recompletions have not and may not result in
economically recoverable reserves. The cost of recompleting a well
producing from the Codell formation is about one third of the cost of a new
well. If the recompletion work is performed, PDC will charge the
Partnership for the direct costs of recompletions, and the Partnership will pay
the Partnership’s proportionate share of costs based on the operating costs
sharing ratios of the Partnership out of Partnership revenues earned from oil
and gas sales. Based on the current economic environment, the
Managing General Partner has no immediate plans to initiate recompletion
activities in the Codell formation of the Wattenberg Field wells. The
Partnership intends to re-evaluate the feasibility of commencing these
recompletion activities as current economic conditions improve.
Title to
Properties
The
Partnership holds record title in its name to the working interest in each
well. PDC provides an assignment of working interest for the well
bore, prior to the spudding of the well and effective the date of the spudding
of the well, to the Partnership in accordance with the D&O
Agreement. Upon completion of the drilling of all of the Partnership
wells, these assignments are recorded in the applicable
county. Investor Partners rely on PDC to use its best judgment to
obtain appropriate title to these working interests. Provisions of
the Limited Partnership Agreement (the “Agreement”), generally relieve PDC from
errors in judgment with respect to the waiver of title defects. PDC
takes those steps it deems necessary to assure that title to the working
interests is acceptable for purposes of the Partnership. For
additional information, see Item 2, Properties – Title to
Properties.
Well
Operations
General. As operator, PDC
represents the Partnership in all operating matters, including the drilling,
testing, completion, recompletion and equipping of wells and the marketing and
sale of the Partnership’s oil and natural gas production from the
wells. PDC is the operator of all of the wells in which the
Partnership owns an interest.
PDC, may
in certain circumstances, provide equipment and supplies, and perform salt water
disposal services and other services for the Partnership. PDC sold
equipment to the Partnership as needed in the drilling or completion of
Partnership wells. All equipment and services were sold at the lesser
of cost or competitive prices in the area of operations.
Gas Pipeline and
Transmission. The transmission
and gathering lines, which are owned either by PDC or other third parties and
which transport the Partnership's natural gas production, are subject to
seasonal curtailment and occasional limitations due to repairs, improvements or
as a result of priority transportation agreements with other natural gas
transporters. Seasonal curtailment typically occurs during July and
August as a result of high atmospheric temperatures which reduce compressor
capacity. This reduction in production typically amounts to less than
five percent of normal monthly production. The cost, timing and
availability of gathering pipeline connections and service varies from area to
area, well to well, and over time. When a significant amount of
development work is being done in an area, production can temporarily exceed the
available markets and pipeline capacity to move natural gas to more distant
markets. This excess supply can lead to lower natural gas prices
relative to other areas as the producers compete for the available markets by
reducing prices. This excess supply can also lead to curtailments of
production and periods when wells are shut-in due to lack of
market.
Sale of Production. In accordance
with the D&O Agreement, PDC markets the oil and natural gas produced from
the Partnership’s wells on a competitive basis, at what it believes to be, the
best available terms and prices generally, under contracts with indexed monthly
pricing provisions. PDC does not enter into any commitment of future
production that does not directly benefit the Partnership. Generally,
purchase contracts for the sale of oil are cancelable on 30 days notice, whereas
purchase contracts for the sale of natural gas may range from spot market sales
of short duration to multi-year contracts requiring the dedication of the
natural gas produced from a well for a period ranging up to the life of the
well.
The gas
is sold at negotiated prices based upon a number of factors, including the
quality of the gas, well pressure, estimated remaining reserves, prevailing
supply conditions and any applicable price regulations promulgated by the
Federal Energy Regulatory Commission, or FERC. The Partnership sells
oil produced by its wells to local oil purchasers at spot prices. The produced
oil is stored in tanks at or near the location of the Partnership’s wells for
routine pickup by oil transport trucks.
In
general, the Partnership has been and expects to continue to be able to produce
and sell oil and natural gas from the Partnership’s wells without significant
curtailment and at locally competitive prices. The Partnership does
experience limited curtailments from time to time due to pipeline maintenance
and operating issues as discussed above. The Partnership experienced
a minor curtailment of production in the Piceance Basin due to limited
compression and pipeline capacity throughout most of fourth quarter
2008. This interruption, due to third party infrastructure, was
corrected in early 2009.
Price +Risk
Management. Price volatility is a very significant and a
potential destabilizing factor in the oil and natural gas production
industry. To help manage the risks associated with the oil and
natural gas industry, the Partnership proactively employs strategies to reduce
the effects of commodity price volatility on cash flows by utilizing commodity
based derivative instruments to manage a portion of the exposure to price
volatility. These instruments consist of Colorado Interstate Gas
Index, or CIG, based contracts for Colorado natural gas production, basis
protection swaps and New York Mercantile Exchange, or NYMEX, based contracts for
Colorado oil production, and natural gas production. The contracts
provide price protection for committed and anticipated oil and natural gas
sales. The Partnership's policies prohibit the use of oil and natural
gas futures, swaps, basis protection swaps or options for speculative purposes
and permit utilization of derivatives only if there is an underlying physical
position. While the Partnership’s derivative instruments are utilized
to manage the impact of price volatility of its oil and natural gas production,
the Partnership has elected not to prepare the documentation required to
designate any of the Partnership’s derivative instruments as hedges under the
terms of Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities. Thus, the
Partnership is required to recognize changes in the fair value of its derivative
positions in Partnership earnings each reporting period thereby resulting in the
potential for significant earnings volatility. Along with realized
gains or losses, these changes in fair value are classified as “Oil and gas
price risk management, net” on the statements of operations. See Note
2, Summary of Significant
Accounting Policies−Derivative Financial Instruments, to the
Partnership’s accompanying financial statements included in this
report.
The sale
of the Partnership’s production is subject to market price fluctuations for
natural gas sold in the spot market and under market index
contracts. PDC, as Managing General Partner, continues to evaluate
the potential for reducing these risks by entering into derivative
transactions. The Managing General Partner may close out any portion
of derivatives that may exist from time to time which may result in a realized
gain or loss on that derivative transaction. The Partnership manages
price risk on only a portion of its anticipated production, so the remaining
portion of its production is subject to the full fluctuation of market
pricing. As of June 30, 2009, the Partnership has oil and natural gas
derivatives in place covering 71% of its expected oil production and 79% of its
expected natural gas production for the remainder of 2009.
The
Partnership utilizes financial derivatives to establish “floors,” “collars,”
“fixed-price swaps” or “basis protection swaps” on the possible range of the
prices realized for the sale of natural gas and oil. These are
recorded on the balance sheet at fair value with changes in fair values
recognized currently in the statement of operations under the caption "Oil and
gas price risk management, net." PDC, as Managing General Partner of
the Partnership, enters into derivative transactions on behalf of the
Partnership in the same manner in which it enters into transactions for
itself. “Floors” contain a floor price (put) whereby PDC, as Managing
General Partner, receives the market price from the purchaser and the difference
between the market price and floor price from the counterparty if the commodity
market price falls below the floor strike price, but receives no payment when
the commodity market price exceeds the floor price. For “swap”
instruments, if the market price is below the fixed contract price, PDC, as
Managing General Partner, receives the market price from the purchaser and
receives the difference between the market price and the fixed contract price
from the counterparty. If the market price is above the fixed
contract price, PDC, as Managing General Partner, receives the market price from
the purchaser and pays the difference between the market price and the fixed
contract price to the counterparty. “Collars” contain a fixed floor
price (put) and ceiling price (call). If the market falls below the
fixed put strike price, PDC, as Managing General Partner, receives the market
price from the purchaser and receives the difference between the put strike
price and market price from the counterparty. If the market price
exceeds the fixed call strike price, PDC, as Managing General Partner, receives
the market price from the purchaser and pays the difference between the call
strike price and market price to the counterparty. If the market
price is between the call and put strike price, no payments are due to or from
the counterparty. Finally, “basis protection swaps” are arrangements
that guarantee a price differential for natural gas valued at a specified
pricing point, or hub. For Partnership CIG basis protection swaps
that have a negative pricing differential to NYMEX, PDC as Managing General
Partner receives a payment from the counterparty if the price differential is
greater than the stated terms of the contract and pays the counterparty if the
price differential is less than the stated terms of the contract. See
Item 1A, Risk Factors -
The
Partnership's derivative activities could result in reduced future revenue and
cash flows compared to the level the Partnership might experience if no
derivative instruments were in place.
The
Partnership participates on a pro-rata basis, in all derivative transactions
entered into by the Managing General Partner in a given area. The
Partnership’s allocation of derivative positions is based on the Partnership’s
percentage of estimated production to total estimated production from a given
area on a monthly basis. The transactions are on a production month
basis. Therefore, the Partnership may participate in a derivative for
a future period before it has production from that area. Prior to
September 30, 2008, as estimated future production volumes increased due to
continued drilling and wells placed into production, the allocation of
derivative positions between PDC’s corporate interests and this Partnership,
changed on a pro-rata basis. As of September 30, 2008, the allocation
of derivative positions was fixed, based on the estimated future production at
this date, between the Managing General Partner’s corporate interests and each
sponsored drilling partnership. For positions entered into subsequent
to September 30, 2008, specific designations of the quantities between the
Managing General Partner’s corporate interests and each sponsored drilling
partnership, including this Partnership, are allocated and fixed at the time the
positions are entered into based on estimated future production. The
Partnership believes that in a rapidly changing price environment, derivative
positions are desirable to obtain more predictable cash flows and to reduce the
impact of possible future price declines.
D&O
Agreement. The Partnership has entered into the D&O
Agreement with PDC. The D&O Agreement provides that the operator
conducts and directs drilling operations, including well recompletions, and has
full control of all operations on the Partnership's wells. Generally,
an operator has limited liability to the Partnership for losses sustained or
liabilities incurred, except as may result from the operator's negligence or
misconduct. Under the terms of the D&O Agreement, PDC may
subcontract certain functions as operator for Partnership wells. PDC
retains responsibility for work performed by subcontractors.
To the
extent the Partnership has less than a 100% working interest in a well, the
Partnership paid only its proportionate share of total lease, development, and
operating costs, and receives its proportionate share of production subject only
to royalties and overriding royalties. The Partnership is responsible only for
its obligations and is liable only for its proportionate working interest share
of the costs of developing and operating the wells.
Under the
D&O Agreement, the operator may provide all necessary labor, vehicles,
supervision, management, accounting, and overhead services for normal production
operations, and may deduct from Partnership revenues a fixed monthly charge for
these services. The charge for these operations and field supervision fees
(referred to as “well tending fees”) for each producing well are based on
competitive industry rates, which vary based upon the area of
operation. The well tending fees and administration fees may be
adjusted annually to an amount equal to the rates initially established by the
D&O Agreement multiplied by the then current average of the Oil and Gas
Extraction Index and the Professional and Technical Services Index, as published
by the United States Department of Labor, Bureau of Labor Statistics, provided
that the charge may not exceed the rate which would be charged by the comparable
operators in the area of operations. This average is commonly
referred to as the Accounting Procedure Wage Index Adjustment which is published
annually by the Council of Petroleum Accountants Societies, or
COPAS.
Under the
D&O Agreement the Partnership has the right to take in kind and separately
dispose of its share of all oil and natural gas produced from its
wells. In accordance with the D&O Agreement, the Partnership
designated PDC as its agent to market its production and authorized the operator
to enter into and bind the Partnership in those agreements as it deems in the
best interest of the Partnership for the sale of its oil and/or natural
gas. Where pipelines owned by PDC are used in the delivery of natural
gas to market, PDC charges a market rate gathering fee not to exceed that which
would be charged by a non-affiliated third party for a similar
service.
The
D&O Agreement remains in force as long as any well or wells produce, or are
capable of economic production, and for an additional period of 180 days from
cessation of all production, or until PDC is replaced as Managing General
Partner as provided for in the D&O Agreement.
Production Phase of
Operations
When
Partnership wells are "complete" (i.e., drilled, fractured or stimulated, and
all surface production equipment and pipeline facilities necessary to produce
the well are installed), production operations commence on each
well. All Partnership wells are complete, and production operations
are currently being conducted with regard to each of the 23 productive
wells.
PDC
markets the Partnership’s natural gas to commercial end users, interstate or
intrastate pipelines or local utilities, primarily under market sensitive
contracts in which the price of natural gas sold varies as a result of market
forces. Some leases, and thus the natural gas derived from wells
drilled on those leases, may have been dedicated to particular markets at the
time the Partnership drilled wells on such leases, or subsequent to, as part of
the natural gas marketing arrangements. In general, the Partnership
has been, and expects to continue to be able to, produce and sell natural gas
from Partnership wells without significant curtailment and at competitive
prices. The Partnership does experience limited curtailments from
time to time due to pipeline maintenance and operating issues of the pipeline
operators. For instance, the Partnership experienced an approximate
10% to 15% curtailment of production volumes in the Piceance Basin due to
limited compression and pipeline capacity throughout most of the fourth quarter
in 2008. This interruption, due to third party infrastructure, was
corrected in early 2009.
The
majority of the Partnership’s wells in the Wattenberg Field in Colorado produce
oil in addition to natural gas. The Managing General Partner is
currently able to sell all the oil that the Partnership can produce under
existing sales contracts with petroleum refiners and marketers. The
Partnership does not refine any of its oil production. The
Partnership’s crude oil production is sold to purchasers at or near the
Partnership’s wells under both short and long-term purchase contracts with
monthly pricing provisions.
PDC, on
behalf of the Partnership, may enter into fixed price contracts, or utilize
derivatives, including collars, swaps or basis protection swaps, in order to
offset some or all of the price variability for particular periods of
time. The use of derivatives may entail fees, including the time
value of money for margin requirements, which are charged to the
Partnership.
Seasonal
factors, such as effects of weather on prices received and costs incurred, and
availability of pipeline capacity, may impact the Partnership's results of
operations. In addition, both sales volumes and prices are subject to
demand factors with a seasonal component.
Revenues, Expenses and
Distributions
The
Partnership's share of production revenue from a given well is burdened by
and/or subject to royalties and overriding royalties, monthly operating charges,
taxes and other operating costs.
It is
PDC's practice to deduct operating expenses from the production revenue for the
corresponding period and to defer the collection of operating expenses to future
periods when revenues are insufficient to render full payment and a liability is
recorded by the Partnership.
Production, Sales, Prices
and Lifting Costs
The
following table sets forth information regarding the Partnership’s production
volumes, oil and natural gas sales, average sales price received and average
lifting cost incurred for the periods indicated.
|
Year
Ended
|
Year
Ended
|
|||||||
|
December 31, 2008
|
December 31, 2007
|
|||||||
|
Production
|
||||||||
|
Oil
(Bbls)
|
9,672 | 12,961 | ||||||
|
Natural
gas
(Mcf)
|
446,018 | 463,307 | ||||||
|
Natural
gas equivalent (Mcfe)
|
504,050 | 541,073 | ||||||
|
Oil
and Gas Sales
|
||||||||
|
Oil
sales
|
$ | 862,214 | $ | 752,295 | ||||
|
Gas
sales
|
2,901,668 | 2,267,215 | ||||||
|
Total
oil and gas sales
|
$ | 3,763,882 | $ | 3,019,510 | ||||
|
Average
Sales Price (excluding realized gain (loss) on
derivatives)
|
||||||||
|
Oil
(per
Bbl)
|
$ | 89.15 | $ | 58.04 | ||||
|
Natural
gas (per
Mcf)
|
6.51 | 4.89 | ||||||
|
Natural
gas equivalent (per
Mcfe)
|
7.47 | 5.58 | ||||||
|
Realized
Gain (Loss) on Derivatives, net
|
||||||||
|
Oil
derivatives - realized loss
|
$ | (45,042 | ) | $ | (3,604 | ) | ||
|
Natural
gas derivatives - realized gain
|
115,356 | 175,512 | ||||||
|
Total
realized gain on derivatives, net
|
$ | 70,314 | $ | 171,908 | ||||
|
Average
Sales Price (including realized gain (loss) on
derivatives)
|
||||||||
|
Oil
(per
Bbl)
|
$ | 84.49 | $ | 57.76 | ||||
|
Natural
gas (per
Mcf)
|
6.76 | 5.27 | ||||||
|
Natural
gas equivalent (per
Mcfe)
|
7.61 | 5.90 | ||||||
|
Average
Production Cost (Lifting Cost) (per
Mcfe)
|
$ | 1.79 | $ | 1.44 | ||||
Definitions
used throughout Item 1, Business:
|
|
·
|
Bbl
– One barrel or 42 U.S. gallons liquid
volume
|
|
|
·
|
MBbl
– One thousand barrels
|
|
|
·
|
Mcf
– One thousand cubic feet
|
|
|
·
|
Mcfe
– One thousand cubic feet of natural gas equivalents, based on a ratio of
6 Mcf for each barrel of oil, which reflect the relative energy
content
|
|
|
·
|
MMcf
– One million cubic feet
|
|
|
·
|
MMcfe
– One million cubic feet of natural gas
equivalents
|
Production
as shown in the table is determined by multiplying the gross production volume
of properties in which the Partnership has an interest by the percentage of the
leasehold or other property interest the Partnership owns.
The
Partnership utilizes commodity based derivative instruments to manage a portion
of its exposure to commodity price volatility of its natural gas and oil
sales. Production costs represent oil and gas operating expenses
which include severance and ad valorem taxes as reflected in the Partnership’s
financial statements. See Item 7, Management's Discussion and Analysis of
Financial Condition and Results of Operations – Production and Operating
Costs.
Oil and Natural Gas
Reserves
All of
the Partnership’s natural gas and oil reserves are located in the United
States. Ryder Scott Company, L.P., an independent engineer prepared
the reserve reports for 2008 and 2007. The independent engineer’s estimates are
made using available geological and reservoir data as well as production
performance data including data provided by the Managing General
Partner. The estimates are prepared with respect to reserve
categorization, using the definitions for proved reserves set forth in
Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and
guidance. When preparing the Partnership’s reserve estimates, the
independent engineers did not independently verify the accuracy and completeness
of information and data furnished by the Partnership with respect to ownership
interests, oil and natural gas production, well test data, historical costs of
operations and developments, product prices, or any agreements relating to
current and future operations of properties and sales of
production. The Partnership’s independent reserve estimates are
reviewed and approved by the Managing General Partner’s internal engineering
staff and management.
The
tables below set forth information as of December 31, 2008, regarding the
Partnership’s proved reserves as estimated by Ryder Scott Company,
L.P. Reserves cannot be measured exactly, because reserve estimates
involve subjective judgment. The estimates are reviewed periodically
and adjusted to reflect additional information gained from reservoir performance
data, new geological and geophysical data and economic
changes. Neither the present value of estimated future net cash flows
nor the standardized measure is intended to represent the current market value
of the estimated oil and natural gas reserves which the Partnership
owns. The Partnership’s estimated proved undeveloped reserves
represent the reserves attributable to the planned future recompletion of the
Codell formation in the 16 Wattenberg Field wells.
|
As of December 31,
2008
|
||||||||||||
|
Oil (MBbl)
|
Gas (MMcf)
|
Total (MMcfe)
|
||||||||||
|
Proved
developed
|
46 | 4,390 | 4,666 | |||||||||
|
Proved
undeveloped
|
211 | 1,166 | 2,432 | |||||||||
|
Total
Proved
|
257 | 5,556 | 7,098 | |||||||||
|
Proved
|
Proved
|
Total
|
||||||||||
|
Developed
|
Undeveloped
|
Proved
|
||||||||||
|
(in
thousands)
|
(in
thousands)
|
(in
thousands)
|
||||||||||
|
Estimated
future net cash flows
|
$ | 12,094 | $ | 7,138 | $ | 19,232 | ||||||
|
Standardized
measure of estimated future cash flows
|
6,880 | 3,007 | 9,887 | |||||||||
Estimated
future net cash flows represent the estimated future gross revenues expected to
be generated from the production of proved reserves, net of estimated production
costs and future development costs, using prices and costs in effect at December
31, 2008. The prices used in the Partnership’s reserve reports yield
weighted average wellhead prices of $38.33 per barrel of oil and $4.70 per Mcf
of natural gas. These prices should not be interpreted as a
prediction of future prices, nor do they reflect the value of the Partnership’s
commodity hedges in place at December 31, 2008. The amounts shown do
not give effect to non-property related expenses, such as direct costs - general
and administrative expenses, or to depreciation, depletion and
amortization.
The
standardized measure of discounted future net cash flows is calculated in
accordance with Statement of Financial Accounting Standards, or SFAS, No. 69,
Disclosures About Oil and Gas
Producing Activities, which requires the future cash flows to be
discounted. The discount rate used was 10%. Additional
information on this measure is presented in Supplemental Oil and Gas Information
- Unaudited, Standardized
Measure of Discounted Future Net Cash Flows and Changes Therein Relating to
Proved Oil and Gas Reserves, included in this report.
Insurance
PDC, in
its capacity as operator, has purchased well pollution, public liability and
worker’s compensation insurance policies for its own benefit as well as the
benefit of the Partnership, however insurance may not be sufficient to cover all
potential liabilities. Each partner who chose to participate as an
additional general partner had potential unlimited liability for unforeseen
events such as blowouts, lost circulation, and stuck drill pipe, occurring prior
to converting to limited partners, which could result in unanticipated
additional liability materially in excess of the per unit subscription
amount. However, upon conversion to limited partners on February 8,
2005, all investor partners’ liability became limited. The remaining
general partner is PDC, also the Managing General Partner.
PDC has
obtained various insurance policies, as described below, and intends to maintain
these policies subject to PDC's analysis of their premium costs, coverage and
other factors. PDC may, in its sole discretion, increase or decrease
the policy limits and types of insurance from time to time as deemed appropriate
under the circumstances, which may vary materially. PDC is the named
beneficiary under each policy and pays the premiums for each policy, except with
respect to the insurance coverage referred to in Items 2 and 5 below in which
case the Managing General Partner and the Partnership are co-insured and
co-beneficiaries. Additionally, PDC as operator of the Partnership's
wells requires all of PDC's subcontractors to carry liability insurance coverage
with respect to the subcontractors’ activities. In the event of a
loss due to the subcontractors’ performance, the insurance policies of the
particular subcontractor at risk may be drawn upon before the insurance of the
Managing General Partner or that of the Partnership. PDC has obtained
and expects to maintain the following insurance.
|
|
1.
|
Worker's
compensation insurance in full compliance with the laws for the states in
which the operator has employees;
|
|
|
2.
|
Operator's
bodily injury liability and property damage liability insurance, each with
a limit of $1 million;
|
|
|
3.
|
Employer's
liability insurance with a limit of not less than $1
million;
|
|
|
4.
|
Automobile
public liability insurance with a limit of not less than $1 million per
occurrence, covering all PDC owned or leased automobile equipment;
and
|
|
|
5.
|
Operator's
umbrella liability insurance with a limit of $50 million for each well
location and in the aggregate.
|
PDC’s
management, as Managing General Partner, believes that adequate insurance,
including insurance by PDC’s subcontractors, has been provided to the
Partnership with coverage sufficient to protect the Investor Partners against
the foreseeable risks of drilling, recompletions and reworks. PDC has
maintained liability insurance, including umbrella liability insurance, of at
least two times the Partnership’s capitalization, up to a maximum of $50
million, but in no event less than $10 million during drilling or recompletion
operations.
Competition and
Markets
Competition
is high among persons and companies involved in the exploration for and
production of oil and natural gas. The Partnership competes with
entities having financial resources and staffs substantially larger than those
available to the Partnership. There are thousands of oil and natural
gas companies in the United States. The national supply of natural
gas is widely diversified. As a result of this competition and FERC
and Congressional deregulation of natural gas and oil prices, prices are
generally determined by competitive forces.
The
marketing of any oil and natural gas produced by the Partnership is affected by
a number of factors which are beyond the Partnership's control and the exact
effect of which cannot be accurately predicted. These factors include
the volume and prices of crude oil imports, the availability and cost of
adequate pipeline and other transportation facilities, the marketing of
competitive fuels, such as coal and nuclear energy, and other matters affecting
the availability of a ready market, such as fluctuating supply and
demand. Among other factors, the supply and demand balance of crude
oil and natural gas in world markets may have caused significant variations in
the prices of these products over recent years.
FERC
Order No. 636, issued in 1992, restructured the natural gas industry by
requiring natural gas pipelines to separate their storage, sales and
transportation functions and establishing an industry-wide structure for
"open-access" transportation service. FERC Order No. 637, issued in
February 2000, further enhanced competitive initiatives, by removing price caps
on short-term capacity release transactions.
FERC
Order No. 637 also enacted other regulatory policies that increase the
flexibility of interstate natural gas transportation, maximize shippers' supply
alternatives, and encourage domestic gas production in order to meet projected
increases in gas demand. These increases in demand come from a number
of sources, including as boiler fuel to meet increased electric power generation
needs and as an industrial fuel that is environmentally preferable to
alternatives such as nuclear power and coal. This trend has been
evident over the past year, particularly in the western U.S., where natural gas
is the preferred fuel for environmental reasons, and electric power demand has
directly increased the demand for natural gas.
The
combined impact of FERC Order No. 636 and No. 637 has been to increase the
competition among natural gas suppliers from the different natural gas producing
regions in the U.S.
In 1995,
the North American Free Trade Agreement, or NAFTA, eliminated trade and
investment barriers in the United States, Canada, and Mexico, increasing foreign
competition for gas production. Legislation that Congress may
consider with respect to oil and natural gas may increase or decrease the demand
for the Partnership's production in the future, depending on whether the
legislation is directed toward decreasing demand or increasing
supply.
Members
of the Organization of Petroleum Exporting Countries, or OPEC, establish prices
and production quotas for petroleum products from time to time, with the intent
of reducing the current global oversupply and maintaining or increasing price
levels. PDC is unable to predict what effect, if any, future OPEC
actions will have on the quantity of, or prices received for, oil and natural
gas produced and sold from the Partnership's wells.
The
Partnership’s well fields are crossed by pipelines belonging to Encana, DCP
Midstream LP (“DCP”), Williams Production, RMT (“Williams”) and
others. These companies have all traditionally purchased substantial
portions of their supply from Colorado producers. Transportation on
these systems requires that delivered natural gas meet quality standards and
that a tariff be paid for quantities transported.
Sales of
natural gas from the Partnership's wells to DCP and Williams are made on the
spot market via open access transportation arrangements through Williams or
other pipelines. As a result of FERC regulations that require
interstate gas pipeline companies to separate their merchant activities from
their transportation activities and require these companies to release available
capacity on both a short and a long-term basis, local distribution companies
have taken an increasingly active role in acquiring their own natural gas
supplies. Consequently, pipelines and local distribution companies
(utilities) are buying natural gas directly from natural gas producers and
marketers, and retail unbundling efforts are causing many end-users to buy their
own reserves. Activity by state regulatory commissions to review
local distribution company procurement practices more carefully and to unbundle
retail sales from transportation has caused natural gas purchasers to minimize
their risks in acquiring and attaching natural gas supply and has increased
competition in the natural gas marketplace.
Natural Gas and Oil
Pricing
PDC
markets the natural gas and oil from Partnership wells in Colorado subject to
market sensitive contracts, the price of which increases or decreases with
market forces beyond control of the Partnership. Currently, PDC sells
Partnership gas in the Piceance Basin to Williams, which has an extensive
gathering and transportation system in the field. In the Wattenberg
Field, the gas is sold primarily to DCP, which gathers and processes the gas and
liquefiable hydrocarbons produced. Natural gas produced in Colorado
may be impacted by changes in market prices on a national level, as well as
changes in the market for natural gas within the Rocky Mountain
Region. Sales may be affected by capacity interruptions on pipelines
transporting natural gas out of the region.
Through
December 31, 2008, PDC sold 100% of the crude oil from the Partnership’s wells
to Teppco Crude Oil, LP (“Teppco”). The oil is picked up at the well
site and trucked to either refineries or oil pipeline interconnects for
redelivery to refineries. Oil prices fluctuate not only with the general market
for oil as may be indicated by changes in the NYMEX, but also due to changes in
the supply and demand at the various refineries. The cost of trucking
or transporting the oil to market affects the price the Partnership ultimately
receives for the oil. Beginning January 1, 2009, the Partnership
began selling the majority of its crude oil to Suncor Energy Marketing, Inc.
(“Suncor”).
Governmental
Regulation
While the
prices of oil and natural gas are set by the market, other aspects of the
Partnership's business and the oil and natural gas industry in general are
heavily regulated. The availability of a ready market for oil and
natural gas production depends on several factors beyond the Partnership's
control. These factors include regulation of production, federal and
state regulations governing environmental quality and pollution control, the
amount of oil and natural gas available for sale, the availability of adequate
pipeline and other transportation and processing facilities and the marketing of
competitive fuels. State and federal regulations generally are
intended to protect consumers from unfair treatment and oppressive control, to
reduce the risk to the public and workers from the drilling, completion,
production and transportation of oil and natural gas, to prevent waste of oil
and natural gas, to protect rights of owners in a common reservoir and to
control contamination of the environment. Pipelines are subject to
the jurisdiction of various federal, state and local agencies. PDC
management, as Managing General Partner, believes that the Partnership is in
compliance with such statutes, rules, regulations and governmental orders,
although there can be no assurance that this is or will remain the
case. The following summary discussion of the regulation of the
United States oil and natural gas industry is not intended to constitute a
complete discussion of the various statutes, rules, regulations and
environmental orders to which the Partnership's operations may be
subject.
Environmental
Regulation
The
Partnership’s operations are subject to numerous laws and regulations governing
the discharge of materials into the environment or otherwise relating to
environmental protection. Public interest in the protection of the
environment has increased dramatically in recent years. The trend of
more expansive and tougher environmental legislation and regulations could
continue. To the extent laws are enacted or other governmental action
is taken that restricts drilling or imposes environmental protection
requirements that result in increased costs and reduced access to the natural
gas industry in general, our business and prospects could be adversely
affected. In December 2008, the State of Colorado’s Oil and Gas
Conservation Commission finalized new broad-based wildlife protection and
environmental regulations for the oil and natural gas industry which are
expected to increase the Partnership’s well recompletion costs and ongoing level
of production and operating costs. Partnership expenses relating to
preserving the environment have risen over the past two years and are expected
to continue in 2009 and beyond. While environmental regulations have
had no materially adverse effect on its operations to date, no assurance can be
given that environmental regulations or interpretations of such regulations will
not in the future, result in a curtailment of production or otherwise have a
materially adverse effect on Partnership operations.
The
Partnership generates wastes that may be subject to the Federal Resource
Conservation and Recovery Act, or RCRA, and comparable state
statutes. The U.S. Environmental Protection Agency, or EPA, and
various state agencies have limited the approved methods of disposal for certain
hazardous and non-hazardous wastes. Furthermore, certain wastes
generated by our operations that are currently exempt from treatment as
"hazardous wastes" may in the future be designated as "hazardous wastes," and
therefore be subject to more rigorous and costly operating and disposal
requirements.
Proposed
Regulation
Various
legislative proposals and proceedings that might affect the petroleum and
natural gas industries occur frequently in Congress, FERC, state commissions,
state legislatures, and the courts. These proposals involve, among
other things, imposition of direct or indirect price limitations on natural gas
production, expansion of drilling opportunities in areas that would compete with
Partnership production, imposition of land use controls, landowners' "rights"
legislation, alternative fuel use requirements and/or tax incentives and other
measures. The petroleum and natural gas industries historically has
been very heavily regulated; therefore, there is no assurance that the less
stringent regulatory approach recently pursued by FERC and Congress will
continue. The Partnership cannot determine to what extent its future
operations and earnings will be affected by new legislation, new regulations, or
changes in existing regulation, at federal, state or local
levels.
Operating
Hazards
The
Partnership's production operations include a variety of operating risks,
including but not limited to the risk of fire, explosions, blowouts, cratering,
pipe failure, casing collapse, abnormally pressured formations, and
environmental hazards such as natural gas leaks, ruptures and discharges of
toxic gas. The occurrence of any of these could result in substantial
losses to the Partnership due to injury and loss of life, severe damage to and
destruction of property, natural resources and equipment, pollution and other
environmental damage, clean-up responsibilities, regulatory investigation,
criminal proceedings and penalties and suspension of
operations. Pipeline, gathering and transportation operations are
subject to the many hazards inherent in the natural gas industry. These hazards
include damage to wells, pipelines and other related equipment, damage to
property caused by hurricanes, floods, fires and other acts of God, inadvertent
damage from construction equipment, leakage of natural gas and other
hydrocarbons, fires and explosions and other hazards that could also result in
personal injury and loss of life, pollution and suspension of
operations.
Any
significant problems related to Partnership wells could adversely affect our
ability to conduct operations. In accordance with customary industry practice,
the Partnership maintains insurance against some, but not all, potential risks;
however, there can be no assurance that such insurance will be adequate to cover
any losses or exposure for liability. The occurrence of a significant event not
fully insured against could materially adversely affect Partnership operations
and financial condition. We cannot predict whether insurance will continue to be
available at premium levels that justify its purchase or whether insurance will
be available at all. Furthermore, the Partnership is not insured
against economic losses resulting from damage or destruction to third party
property, such as the Rockies Express pipeline; such an event could result in
significantly lower regional prices or the Partnership’s inability to deliver
natural gas.
Available
Information
The
Partnership is subject to the reporting and information requirements of the
Securities Exchange Act of 1934, as amended, and is as a result obligated to
file periodic reports, proxy statements and other information with the
SEC. The SEC maintains a website that contains the annual, quarterly,
and current reports, proxy and information statements, and other information
regarding the Partnership, which the Partnership electronically files with the
SEC. The address of that site is http://www.sec.gov. The
Central Index Key, or CIK, for the Partnership is 0001306758. You can
read and copy any materials the Partnership files with the SEC at the SEC’s
Public Reference Room at 100 F Street, N.E., Room 1850, Washington,
D.C. 20549. You may obtain information on the operation of
the Public Reference Room by calling the SEC at 1-800-SEC-0330.
|
Item 1A.
|
Risk
Factors
|
In the
course of its normal business, the Partnership is subject to a number of risks
that could adversely impact its business, operating results, financial
condition, and cash distributions. The following is a discussion of
the material risks involved in an investment in the Partnership.
Risks Related to the Global
Economic Crisis
The current global economic
crisis may increase the magnitude and the likelihood of the occurrence of the
negative consequences discussed in many of the risk factors that follow and
result in reduced cash distributions to the Investor
Partners. In particular, consider the risks related to the
rapid deterioration of demand for oil and natural gas resulting from the
economic crisis and the related negative effects on oil and gas
pricing. Similarly, further reductions in oil and gas prices could
result in existing Partnership wells being uneconomical to recomplete which
would reduce remaining Partnership proved reserves. These factors
could limit the Managing General Partner’s ability to execute the Partnership
business plan and result in lower Partnership production, adversely impacting
Partnership income and Investor Partner distributions. Additionally,
the global economic crisis also increases the Partnership’s credit risk
associated with derivative financial institutional counterparty default or oil
and natural gas purchaser non-payment, thus potentially impacting Partnership
liquidity and production operating levels. All of these risks could
have a significant effect on the Partnership’s business, financial results and
Partnership distributions. Any additional deterioration in the
domestic or global economic conditions will further amplify these
results.
Recent disruptions in the
global financial markets and the likely related economic downturn may further
decrease the demand for oil and natural gas and the prices of oil and natural
gas thereby limiting the Partnership’s production and thereby adversely
affecting Partnership profitability and Investor Partner
distributions. During the second half of 2008 and to date,
prices for oil and natural gas decreased over 70% from mid-2008
levels. The well-publicized global financial market disruptions and
the related economic crisis may further decrease demand for oil and gas and
therefore lower oil and gas prices. If there is such an additional
reduction in demand, the production of natural gas in particular may be in
oversupply. There is no certainty as to how long this low price
environment will continue. The Partnership operates in a highly
competitive industry, and certain competitors have lower operating costs in such
an environment. Additionally, the inability of third parties to
finance and build additional pipelines out of the Rockies and elsewhere could
cause significant negative pricing effects. Any of the above factors
could adversely affect the Partnership’s operating results and reduce cash
distributions to the Investor Partners. For more information
regarding the Wattenberg Field recompletion plan, see Item 1 Business, Plan of
Operation.
Risks Pertaining to Natural
Gas and Oil Investments
The oil and natural gas
business is speculative and may be unprofitable and result in the total loss of
investment. The oil and natural gas business is inherently
speculative and involves a high degree of risk and the possibility of a total
loss of investment. The Partnership's business activities may result
in unprofitable well operations, not only from non-productive wells and
recompletions, but also from wells that do not produce oil or natural gas in
sufficient quantities or quality to return a profit on the amounts
expended. The prices of oil and natural gas play a major role in the
profitability of the Partnership. Partnership wells may not produce
sufficient natural gas and oil for investors to receive a profit or even to
recover their initial investment. Only three out of 77 partnerships
sponsored by PDC have, to date, generated cash distributions in excess of
investor subscriptions without giving effect to tax savings.
The Partnership may retain
Partnership revenues if needed for Partnership operations to fully develop the
Partnership's wells; if full development of the Partnership's wells proves
commercially unsuccessful, an individual investor partner might anticipate a
reduction in cash distributions. The Partnership utilized
substantially all of the capital raised in the offering for the drilling and
completion of wells. If the Partnership requires additional capital
in the future, it will have to retain Partnership revenues necessary for these
purposes. Retaining Partnership revenues will result in a reduction
of cash distributions to the investors. Additionally, in the future,
PDC plans to rework or recomplete Partnership wells; however, PDC has not
withheld money from the initial investment for that future
work. Future development of the Partnership's wells may prove
commercially unsuccessful and the further-developed Partnership wells may not
generate sufficient funds from production to increase distributions to Investor
Partners to cover revenues retained. If future development of the
Partnership's wells is not commercially successful using funds retained from
current production revenues, lower future operational revenues could result in a
reduced level of cash distributions to the Investor Partners of the
Partnership.
The inability of one or more
of the Partnership’s customers or derivative counterparties to meet their
obligations may adversely affect Partnership profitability and timing of
distributions to Investor Partners. Substantially all of the
Partnership’s accounts receivable results from natural gas and oil sales to a
limited number of third parties in the energy industry. This
concentration of customers may affect the Partnership’s overall credit risk in
that these entities may be similarly affected by recent changes in economic and
other conditions. In addition, Partnership oil and natural gas
derivatives positions expose the Partnership to credit risk in the event of
nonperformance by counterparties.
Increases in prices of oil
and natural gas have increased the cost of drilling and development and may
adversely affect the performance and profitability of the Partnership in both
the short and long term and may result in reduced cash distributions to the
Investor Partners. In the recent high price environment, most
oil and natural gas companies had increased their expenditures for drilling new
wells. This has resulted in increased demand and higher cost for
oilfield services and well equipment. Because of these higher costs,
the Partnership is subject to a higher risk for decreased profitability during
both future rising or falling, oil and natural gas price
changes.
Natural gas and oil prices
fluctuate unpredictably and a decline in prices of oil and natural gas will
reduce the profitability of the Partnership's production operations and could
result in reduced cash distributions to Investor
Partners. Global economic conditions, political conditions,
and energy conservation have created unstable prices. Revenues of the
Partnership are directly related to natural gas and oil prices. The
prices for domestic natural gas and oil production have varied substantially
over time and by location and are likely to remain extremely
unstable. Revenue from the sale of oil and natural gas increases when
prices for these commodities increase and declines when prices
decrease. These price changes can occur rapidly and are not
predictable nor within the control of the Partnership. A decline in
natural gas and/or oil prices would result in lower revenues for the Partnership
and a reduction of cash distributions to the Investor Partners of the
Partnership. Further, reductions in prices of oil and natural gas may
result in shut-ins thereby resulting in lower production, revenues and cash
distributions. The prices from the fourth quarter of 2008 to date
have been too low to economically justify many drilling operations, including
well recompletions, and it is uncertain how long such low pricing shall
persist.
The high level of drilling
activity, particularly in the Rocky Mountain Region during the past two years,
could result in an oversupply of gas on a regional or national level, resulting
in much lower commodity prices, reduced profitability of the Partnership and
reduced cash distributions to Investor Partners. The high
level of drilling, combined with a reduction in demand resulting from recently
volatile oil and natural gas prices and economic uncertainty, could result in an
oversupply of natural gas. In the Rocky Mountain region, rapid growth
of production and increasing supplies may result in lower prices and production
curtailment due to limitations on available pipeline facilities or markets not
developed to utilize or transport the new supplies. In both cases,
the result would likely result in lower Partnership natural gas sales prices,
reduced profitability for the Partnership and reduced cash distributions to the
Investor Partners. Although additional pipeline capacity became
available in early 2008 with the expansion of Rockies Express Pipeline, pipeline
constraints continue for regional Rocky Mountain natural gas production
transportation to high-demand market areas.
Sufficient insurance
coverage may not be available for the Partnership, thereby increasing the risk
of loss for the General Partners. It is possible that some or
all of the insurance coverage which the Partnership has available may become
unavailable or prohibitively expensive. In that case, PDC might elect
to change the insurance coverage. The general partners could be
exposed to additional financial risk due to the reduced insurance coverage and
due to the fact that they would continue to be individually liable for
obligations and liabilities of the Partnership that arose prior to conversion to
limited partners which occurred on February 8, 2005. Investor
Partners could be subject to greater risk of loss of their investment because
less insurance would be available to protect the Partnership from casualty
losses. Moreover, should the Partnership's cost of insurance become
more expensive, or should the Partnership suffer a significant uninsured
casualty loss, the amount of cash distributions to the investors will be
reduced.
Through their involvement in
the Partnership and other non-partnership activities, the Managing General
Partner and its affiliates have interests which conflict with those of the
Investor Partners; actions taken by the Managing General Partner in furtherance
of its own interests could result in the Partnership being less profitable and a
reduction in cash distributions to the Investor
Partners. PDC's continued active participation in oil and
natural gas activities for its own account and on behalf of other partnerships
organized or to be organized by PDC and the manner in which Partnership revenues
are allocated create conflicts of interest with the Partnership. PDC
has interests which inherently conflict with the interests of the Investor
Partners. The following is an itemization of the material conflicts
of interest of PDC as Managing General Partner of the Partnership and of PDC’s
affiliates:
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PDC
might sponsor additional drilling programs or joint ventures in the
future, that could conflict with the interests of the
Partnership. PDC and affiliates have the right to organize and
manage oil and natural gas drilling programs in the future similar to the
Partnership and to conduct production operations now and in the future on
its own behalf or for other individual investor partners. This
situation could lead to a conflict between the position of PDC as Managing
General Partner of the Partnership and the position of PDC or its
affiliates as managing general partner or sponsor of additional
programs.
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PDC
has a fiduciary duty as Managing General Partner to the
Partnership. PDC acts as managing general partner currently for
33 limited partnerships, including this Partnership, and is accountable to
all of the partnerships as a fiduciary. PDC therefore has a
duty to exercise good faith and deal fairly with the investor partners of
each partnership. PDC’s actions taken on behalf of one or more
of these partnerships could be disadvantageous to the Partnership and
could fall short of the full exercise of its fiduciary duty to the
Partnership.
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There
are and will continue to be transactions between PDC, its affiliates and
the Partnership. PDC, as operator of the Partnership, has and
will continue to provide drilling, completion and operation services to
the Partnership’s wells. Although the prices that PDC has
charged, and will charge, to the Partnership for the supplies and services
provided by PDC and affiliates to the Partnership will be competitive with
the prices charged by unaffiliated persons for the same supplies and
services, PDC will benefit financially from this
relationship.
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In
operating the Partnership, the Managing General Partner and its affiliates could
take actions which benefit themselves and which do not benefit the
Partnership. These actions could result in the Partnership being less
profitable. In that event, Investor Partners could anticipate a
reduction of cash distributions.
The Partnership and other
partnerships sponsored by PDC, as Managing General Partner, may compete with
each other for prospects, equipment, contractors, and personnel; as a result,
the Partnership may find it more difficult to operate effectively and
profitably. During 2008, PDC operated and managed other
partnerships formed for substantially the same purposes as those of the
Partnership. PDC will operate and manage these partnerships in 2009
and for the foreseeable future. Therefore, a number of partnerships
with unexpended capital funds, including those partnerships formed before and
after the Partnership, may exist at the same time. The Partnership
may compete for equipment, contractors, and PDC personnel (when the Partnership
is also in need of equipment, contractors and PDC personnel), which may make it
more difficult and more costly to obtain equipment and services for the
Partnership. In that event, it is possible that the Partnership would
be less profitable. Additionally, because PDC must divide its
attention in the management of its own corporate interests as well as the
affairs of the 33 limited partnerships PDC has organized in previous programs,
the Partnership will not receive PDC's full attention and efforts at all
times.
The Partnership's derivative
activities could result in reduced revenue and cash flows compared to the level
the Partnership might experience if no derivative instruments were in
place. The Managing General Partner uses derivative
instruments for a portion of the Partnership’s natural gas and oil production to
achieve a more predictable cash flow and to reduce exposure to adverse
fluctuations in the prices of natural gas and oil. These arrangements
expose the Partnership to the risk of financial loss in some circumstances,
including when purchases or sales are different than expected, the counter-party
to the derivative contract defaults on its contract obligations, or when there
is a change in the expected differential between the underlying price in the
derivative agreement and actual prices that we receive. In addition,
derivative arrangements may limit the benefit from changes in the prices for
natural gas and oil. Since the Partnership’s derivatives do not
currently qualify for use of hedge accounting, changes in the fair value of
derivatives are recorded in the Partnership’s income
statements. Accordingly, the Partnership’s net income is subject to
greater volatility than would be reported if its derivative instruments
qualified for hedge accounting. For instance, if oil and natural gas
prices rise significantly, it could result in significant non-cash losses each
quarter which could have a material negative effect on Partnership net
income.
Fluctuating market
conditions and government regulations may cause a decline in the profitability
of the Partnership and a reduction of cash distributions to the Investor
Partners. The sale of any natural gas and oil produced by the
Partnership will be affected by fluctuating market conditions and governmental
regulations, including environmental standards, set by state and federal
agencies. From time-to-time, a surplus of natural gas or oil may
occur in areas of the United States. The effect of a surplus may be
to reduce the price the Partnership receives for its natural gas or oil
production, or to reduce the amount of natural gas or oil that the Partnership
may produce and sell. As a result, the Partnership may not be
profitable. Lower prices and/or lower production and sales will
result in lower revenues for the Partnership and a reduction in cash
distributions to the Investor Partners of the Partnership.
The Partnership is subject
to complex federal, state, local and other laws and regulations that could
adversely affect the cost, manner or feasibility of doing
business. The Partnership’s operations are regulated
extensively at the federal, state and local levels. Environmental and
other governmental laws and regulations have increased the costs to plan,
design, drill, install, operate and abandon oil and natural gas
wells. Under these laws and regulations, the Partnership could also
be liable for personal injuries, property damage and other
damages. Failure to comply with these laws and regulations may result
in the suspension or termination of the Partnership’s operations and subject the
Partnership to administrative, civil and criminal penalties. Moreover, public
interest in environmental protection has increased in recent years, and
environmental organizations have opposed, with some success, certain drilling
projects. Compliance with these regulations and possible liability
resulting from these laws and regulations could result in a decline in
profitability of the Partnership and a reduction in cash distributions to the
Investor Partners of the Partnership.
The
Partnership’s activities are subject to the regulations regarding conservation
practices and protection of correlative rights. These regulations
affect our operations and limit the quantity of natural gas and/or oil we may
produce and sell. A major risk inherent in our drilling plans is the
need to obtain drilling permits from state and local
authorities. Because the Partnership may consider recompleting
various of its Wattenberg wells if the economic environment improves, for which
permits will be required, delays in obtaining regulatory approvals or drilling
permits or the failure to obtain a drilling permit for a well or the receipt of
a permit with unreasonable conditions or costs could have a material adverse
effect on our ability to develop our properties. Additionally, the
natural gas and oil regulatory environment could change in ways that might
substantially increase the financial and managerial costs of compliance with
these laws and regulations and, consequently, adversely affect the Partnership’s
ability to pay distributions to Investor Partners. Illustrative of
these risks are regulations recently enacted by the State of Colorado which
focuses on the oil and gas industry. These multi-faceted regulations
significantly enhance requirements regarding oil and natural gas permitting,
environmental requirements, and wildlife protection. Permitting
delays and increased costs could result from these final
regulations. The Partnership further references sections Government Regulation and
Proposed Regulation in
Item 1, Business, for a
detailed discussion of the laws and regulations that effect Partnership
activities.
Environmental hazards
involved in drilling gas and oil wells may result in substantial liabilities for
the Partnership, a decline in profitability of the Partnership and a reduction
in cash distributions to the Investor Partners. There are
numerous natural hazards involved in the drilling and operation of wells,
including unexpected or unusual formations, pressures, blowouts involving
possible damages to property and third parties, surface damages, personal injury
or loss of life, damage to and loss of equipment, reservoir damage and loss of
reserves. Uninsured liabilities would reduce the funds available to
the Partnership, may result in the loss of Partnership properties and may create
liability for additional general partners. The Partnership may become
subject to liability for pollution, abuses of the environment and other similar
damages, and it is possible that insurance coverage may be insufficient to
protect the Partnership against all potential losses. In that event,
Partnership assets would be used to pay personal injury and property damage
claims and the costs of controlling blowouts or replacing destroyed equipment
rather than for drilling activities. These payments would cause an
otherwise profitable partnership to be less profitable or unprofitable and would
result in a reduction of cash distributions to the Investor Partners of the
Partnership.
Delay in Partnership natural
gas or oil production could reduce the Partnership’s profitability and cash
distributions to the Investor Partners. The Partnership’s
inability to recomplete wells in a timely fashion may result in production
delays. In addition, marketing demands that tend to be seasonal may
reduce or delay production from wells. Wells drilled for the
Partnership may have access to only one potential market. Local
conditions including but not limited to closing businesses, conservation,
shifting population, pipeline maximum operating pressure constraints, and
development of local oversupply or deliverability problems could halt or reduce
sales from Partnership wells. Any of these delays in the production
and sale of the Partnership's natural gas and oil could reduce the Partnership's
profitability, and in that event, the cash distributions to the Investor
Partners of the Partnership would decline.
A significant variance from
the Partnership’s estimated reserves and future net revenues could adversely
affect the Partnership’s cash flows and results of
operations. The accuracy of proved reserves and future net
revenues estimates from such reserves, is a function of the quality of available
geological, geophysical, engineering and economic data and is subject to various
assumptions, including assumptions required by the SEC relating to oil and gas
prices, drilling and operating expenses, and other matters. Although the
estimated proved reserves represent reserves the Partnership reasonably believes
it is certain to recover, actual future production, oil and gas prices,
revenues, taxes, development expenditures, operating expenses and quantities of
recoverable oil and gas reserves will most likely vary from the assumptions and
estimates used to determine proved reserves. Any significant variance could
materially affect the estimated quantities and value of the Partnership’s oil
and gas reserves, which in turn could adversely affect cash flows and results of
operations. In addition, estimates of proved reserves may be adjusted
to reflect many factors, many of which are beyond the Partnership’s control,
including production history, results of development, and prevailing oil and
natural gas prices which are volatile and often fluctuate
greatly. Lower natural gas and oil prices may not only reduce
Partnership revenues, but also may reduce the amount of natural gas and oil that
can be produced economically. As a result, the Partnership may have
to make substantial additional downward adjustments to its estimated proved
reserves. If this occurs or if Partnership estimates of production
data factors change, accounting rules may require the Partnership to write-down
operating assets to fair value, as a non-cash charge to earnings. The
Partnership assesses impairment of capitalized costs of proved natural gas and
oil properties by comparing net capitalized costs to estimated undiscounted
future net cash flows on a field-by-field basis using estimated future
production based upon prices at which the Managing General Partner reasonably
estimates such products may be sold. The Partnership has recorded no
impairments since its operations commenced in July 2004. The
Partnership may incur additional impairment charges in the future, which could
have a material adverse effect on the results of Partnership operations and
Partner’s equity.
The standardized measure of
estimated proved reserves, in accordance with SFAS 69, Disclosures
About Oil and Gas Producing Activities, which assumes a 10%
discount factor, will not necessarily equal the current fair market value of the
estimated oil and gas reserves. In accordance with the reserve
reporting requirements of the SEC, the estimated discounted future net cash
flows from proved reserves are generally based on prices and costs as of the
date of the estimate. Actual future prices and costs may be materially higher or
lower than those as of the date of the estimate. The timing of both the
production and the expenses with respect to the development and production of
oil and gas properties will affect the timing of future net cash flows from
estimated proved reserves and their related present value estimate.
Seasonal weather conditions
may adversely affect the Partnership’s ability to conduct production activities
in some of the areas of operation. Oil and natural gas
operations in the Rocky Mountains are adversely affected by seasonal weather
conditions. In certain areas, drilling and other oil and natural gas activities
are restricted or prevented by weather conditions for up to six months out of
the year. This limits operations in those areas and can intensify competition
during those months for oil field equipment, services, supplies and qualified
personnel, which may lead to periodic shortages. These constraints and the
resulting shortages or high costs could delay operations and materially increase
operating and capital costs and therefore adversely affect profitability, and
could result in a reduction of cash distributions to the Investor
Partners.
A Colorado lawsuit against
PDC, the Managing General Partner of the Partnership, for underpayment of
royalties, could financially harm PDC and the Partnership. A judgment
by the Federal Court against PDC could result in lower oil and gas sales
revenues for the Partnership, reduced profitability and reduced cash
distributions to the Investor Partners. On May 29, 2007,
Glen Droegemueller, individually and as representative plaintiff on behalf of
all others similarly situated, filed a class action complaint against the
Managing General Partner in the District Court, Weld County, Colorado alleging
that the Managing General Partner underpaid royalties on natural gas produced
from wells operated by the Managing General Partner in parts of the State of
Colorado (the “Droegemueller Action”). The plaintiff sought declaratory
relief and to recover an unspecified amount of compensation for underpayment of
royalties paid by us pursuant to leases. The Managing General Partner
removed the case to Federal Court on June 28, 2007. On October 10, 2008,
the court preliminarily approved a settlement agreement between the plaintiffs
and the Managing General Partner, on behalf of itself and the Partnership.
Although the Partnership was not named as a party in the suit, the lawsuit
states that it relates to all wells operated by the Managing General Partner,
which includes a majority of the Partnership’s 16 wells in the Wattenberg
field. The portion of the settlement relating to the Partnership’s
wells for all periods through December 31, 2008 that has been expensed by the
Partnership is approximately $18,000 which includes legal fees of approximately
$1,000. This entire settlement of $17,713 was deposited by the
Managing General Partner into an escrow account on November 3,
2008. Notice of the settlement was mailed to members of the class
action suit in the fourth quarter of 2008. The final settlement was
approved by the court on April 7, 2009. Settlement distribution
checks were mailed in July 2009. During September 2009, all
settlement costs were passed through to the Partners and any required judicial
action from the settlement of the suit was implemented in this
distribution.
Special Risks of an
Investment in the Partnership
A “material weakness”
identified in the Partnership’s internal control over financial reporting and
resulting ineffective disclosure controls and procedures could have a material
adverse effect on the reliability of Partnership financial statements, its
ability to file Partnership public reports on time and provide for accurate and
timely Investor Partner distributions.
Management
of the Managing General Partner assessed the effectiveness of the Partnership’s
internal control over financial reporting as of December 31, 2008 and pursuant
to this assessment, identified a material weakness in the Partnership’s internal
control over financial reporting. The existence of any material weakness means
there is a deficiency, or a combination of deficiencies, in internal control
over financial reporting, such that there is a reasonable possibility that a
material misstatement of the Partnership’s annual or interim financial
statements will not be prevented or detected on a timely basis. The material
weakness relates to the Partnership’s failure to maintain sufficient
documentation to adequately assess the operating effectiveness of internal
control over reporting for the transactions that are directly related to and
processed by the Partnership. For a more detailed discussion of the
Partnership’s material weakness, see Item 9A(T), Controls and Procedures, of
this report. As a result of this material weakness, management of the Managing
General Partner concluded that the Partnership’s disclosure controls and
procedures were not effective as of December 31, 2008.
Failure
by the Partnership to maintain effective internal control over financial
reporting and/or effective disclosure controls and procedures could prevent the
Partnership from being able to prevent fraud and/or provide reliable financial
statements and other public reports or make timely and accurate Investor Partner
distributions. Such circumstances could harm the Partnership’s business and
operating results, cause Investor Partners to lose confidence in the accuracy
and completeness of the Partnership’s financial statements and reports, and have
a material adverse effect on the Partnership’s ability to fully develop and
utilize Partnership assets. These failures may also adversely affect the
Partnership’s ability to file our periodic reports with the SEC on
time.
The partnership units are
not registered and there is no public market for the units. As a
result, an individual investor partner may not be able to sell his or her
units. There is and will be no public market for the units nor
will a public market develop for the units. Investor Partners may not
be able to sell their Partnership interests or may be able to sell them only for
less than fair market value. A sale or transfer of units by an
individual investor partner requires PDC’s, as Managing General Partner, prior
written consent. For these and other reasons, an individual investor
partner must anticipate that he or she will have to hold his or her Partnership
interests indefinitely and will not be able to liquidate his or her investment
in the Partnership. Consequently, an individual investor partner must
be able to bear the economic risk of investing in the Partnership for an
indefinite period of time.
The general partners,
including the Managing General Partner, are individually liable for Partnership
obligations and liabilities that arose prior to conversion to limited partners
that may exceed the amount of their subscriptions, Partnership assets, and the
assets of the Managing General Partner. Under West Virginia
law, the state in which the Partnership was organized, general partners of a
limited partnership have unlimited liability with respect to the
Partnership. Therefore, the additional general partners of the
Partnership were liable individually and as a group for all obligations and
liabilities of creditors and claimants, whether arising out of contract or tort,
in the conduct of the Partnership's operations until such time as the additional
general partners converted to limited partners on February 8,
2005. Upon completion of the drilling phase of the Partnership's
wells, all additional general partnership units were converted into units of
limited partnership interests and thereafter became limited partners of the
Partnership. Irrespective of conversion, the additional general partners will
remain fully liable for obligations and liabilities that arose prior to
conversion. Investors as additional general partners may be liable
for amounts in excess of their subscriptions, the assets of the Partnership,
including insurance coverage, and the assets of the Managing General
Partner.
The Managing General Partner
may not have sufficient funds to repurchase limited partnership units. As
a result of PDC, the Managing General Partner, being a general partner in
several partnerships as well as an actively operating corporation, the
Partnership’s net worth is at risk of reduction if PDC suffers a significant
financial loss. Because the Investor Partners may request the
Managing General Partner to repurchase the units in the Partnership, subject to
certain conditions and restrictions, a significant adverse financial reversal
for PDC could result in the Managing General Partner’s inability to pay for
Partnership obligations or the repurchase of investor units. As a
result, an individual investor partner may not be able to liquidate his or her
investment in the Partnership.
A significant financial loss
by the Managing General Partner could result in PDC's inability to indemnify
additional general partners for personal losses suffered because of Partnership
liabilities. As a result of PDC's commitments as managing
general partner of several partnerships and because of the unlimited liability
of a general partner to third parties, PDC's net worth is at risk of reduction
if PDC suffers a significant financial loss. The partnership
agreement provides that PDC as the Managing General Partner will indemnify all
additional general partners for the amounts of their obligations and losses
which exceed insurance proceeds and the Partnership's assets. Because
PDC is primarily responsible for the conduct of the Partnership's affairs, as
well as the affairs of other partnerships for which PDC serves as managing
general partner, a significant adverse financial reversal for PDC could result
in PDC's inability to pay for Partnership liabilities and
obligations. The additional general partners of the Partnership might
be personally liable for payments of the Partnership's liabilities and
obligations. Therefore, the Managing General Partner's financial
incapacity could increase the risk of personal liability as an additional
general partner because PDC would be unable to indemnify the additional general
partners for any personal losses they suffered arising from Partnership
operations.
A substantial part of the
Partnership’s natural gas and oil production is located in the Rocky Mountain
Region, making it vulnerable to risks associated with operating in a single
major geographic area. The Partnership’s operations are
focused in the Rocky Mountain Region and its producing properties are
geographically concentrated in that area. Because Partnership
operations are not geographically diversified, the success of its operations and
profitability may be disproportionately exposed to the effect of any regional
events, including fluctuations in prices of natural gas and oil produced from
the wells in the region, natural disasters, restrictive governmental
regulations, transportation capacity constraints, curtailment of production or
interruption of transportation, and any resulting delays or interruptions of
production from existing or planned new wells. During the last four
months of 2008, natural gas prices in the Rocky Mountain Region fell
disproportionately when compared to other markets, due in part to continuing
constraints in transporting gas from producing properties in the
region. Because of the concentration of Partnership operations in the
Rocky Mountain Region, and although in late 2008 the Partnership entered into a
significant multi-year basis hedge minimizing the price risk of the
Partnership’s operational concentration in the Rocky Mountain region, such price
decreases could have a material adverse effect on Partnership revenue,
profitability, cash flow and cash distributions to Investor
Partners.
The Managing General
Partner, with respect to its own corporate interests, the Partnership and
various other limited partnerships sponsored by the Managing General Partner,
have been delinquent in filing periodic reports with the
SEC. Consequently, Investor Partners are unable to review the
delinquent partnerships’ respective financial statements as a source of
information for evaluating their investment in the
Partnership. PDC, as an actively operating corporation, and
various limited partnerships which PDC has sponsored and for which PDC serves as
the Managing General Partner are subject to reporting requirements of the
Exchange Act and are obligated to file annual and quarterly reports with the SEC
in accordance with the rules of the SEC. In the course of preparing
corporate financial statements for the quarter ended June 30, 2005, PDC
identified accounting errors in its prior period financial
statements. As a result, on October 17, 2005, PDC’s Board of
Directors, Audit Committee and management concluded that PDC’s previously issued
financial statements could not be relied upon and would be
restated. PDC, as Managing General Partner, made similar
determinations regarding the financial statements of certain of the limited
partnerships which are subject to the Exchange Act reporting
obligations.
Since
June 2007, PDC has become compliant with its corporate Exchange Act filing and
reporting obligations. Additionally, Rockies Region 2007 Limited Partnership,
Rockies Region 2006 Limited Partnership, PDC 2005-A Limited Partnership, PDC
2005-B Limited Partnership, Rockies Region Private Limited Partnership, PDC
2004-A Limited Partnership and PDC 2004-D Limited Partnership have completed all
required SEC filings through June 30, 2009. PDC 2004-B Limited
Partnership (with this filing) has completed all required SEC filings through
December 31, 2008, but is delinquent on all subsequent quarterly filing
requirements. PDC 2004-C Limited Partnership has completed all
required SEC filings through December 31, 2007, but is delinquent on all
subsequent quarterly and annual filing requirements. All remaining
limited partnerships sponsored by PDC which are subject to the Exchange Act have
been, and continue to be, delinquent in filing their respective periodic reports
in accordance with the requirements of the Exchange Act. Until these
partnerships file their delinquent periodic reports, investors will be unable to
review the financial statements of the various limited partnerships as an
additional source of information they can use in their evaluation of their
investment in the Partnership. Currently the Managing General Partner
has in place a compliance effort addressing the delinquent reports of the
various limited partnerships. However, due to the amount of effort,
time and financial resources required to bring the limited partnerships into
compliance with Exchange Act periodic reporting requirements, the Partnership
and the various limited partnerships may be unable to bring their delinquent
reports current and may be unable in the future to file their required periodic
reports with the Securities and Exchange Commission in a timely
manner.
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Item 1B.
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Unresolved
Staff Comments
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None
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Item 2.
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Properties
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The
Partnership’s properties (the “Properties”) consist of working interests in gas
wells and the ownership in leasehold acreage in the spacing units for the 23
wells drilled by the Partnership. The acreage associated with the
spacing units is designated by state rules and regulations in conjunction with
local practice. See the section titled Item 1, Business Drilling Activities and Plan of Operations for
additional information on the Partnership’s properties.
The
Partnership commenced drilling activities immediately following funding on July
28, 2004. All wells were drilled by December 31, 2004 and drilling
operations were completed in March 2005 when the last of the Partnership’s 23
productive development wells were connected to pipelines. The
Partnership’s 23 gross wells represent 20.9 net wells, or the number of gross
wells multiplied by the working interest in the wells owned by the
Partnership. At December 31, 2008, all 23 Partnership wells were
producing. Productive wells consist of producing wells and wells
capable of producing oil and natural gas in commercial
quantities. The 23 wells are the only wells to be drilled by the
Partnership since all of the funds raised in the Partnership offering have been
utilized. The details of these drilling areas are further outlined
below.
The
Wattenberg Field, located north and east of Denver, Colorado, is in the
Denver-Julesburg (DJ) Basin. The typical well production profile has
an initial high production rate and relatively rapid decline, followed by years
of relatively shallow decline. Natural gas is the primary hydrocarbon
produced; however, many wells will also produce oil. The purchase
price for the natural gas may include revenue from the recovery of propane and
butane in the gas stream, as well as a premium for the typical high-energy
content of the natural gas. Wells in the area may include as many as
four productive formations. From shallowest to deepest, these are the
Sussex, the Niobrara, the Codell and the J Sand. The primary
producing zone in most wells is the Codell sand which produces a combination of
natural gas and oil. The Partnership has 16 wells located in this
field.
The Grand
Valley Field is in the Piceance Basin, located near the western border of
Colorado. Wells in the Piceance Basin generally produce natural gas
along with small quantities of oil. The producing interval consists
of a total of 150 to 300 feet of productive sandstone divided in 10 to 15
different zones. The production zones are separated by layers of
nonproductive shale resulting in a total interval of 2,000 to 4,000 feet with
alternating producing and non-producing zones. The natural gas
reserves and production are divided into these numerous smaller
zones. The Partnership has seven wells located in this
field.
Production
Production
commenced during the fourth quarter of 2004, peaked at 352,000 Mcfe during the
quarter ended June 30, 2005 and has continued to decrease as anticipated based
on the projected production decline curves. A complete disclosure of
quarterly production volumes, prices and sales is presented in Item 7, Management’s Discussion and Analysis
of Financial Condition and Results of Operations in this
report.
Oil and Natural Gas
Reserves
All of
the Partnership’s gas and oil reserves are located in the United
States. The Partnership utilized the services of an independent
petroleum engineer, Ryder Scott Company, L.P., for its 2008 and 2007 reserve
reports. The independent engineer’s estimates are made using
available geological and reservoir data as well as production performance data.
The estimates are prepared with respect to reserve categorization, using the
definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a)
and subsequent SEC staff interpretations and guidance. When preparing the
Partnership's reserve estimates, the independent engineer did not independently
verify the accuracy and completeness of information and data furnished by the
Managing General Partner with respect to ownership interests, oil and gas
production, well test data, historical costs of operations and developments,
product prices, or any agreements relating to current and future operations of
properties and sales of production. The Partnership's independent
reserve estimates are reviewed and approved by the Managing General Partner's
internal engineering staff and management. See Supplemental Oil and
Gas Information – Unaudited, Net Proved Oil and Gas
Reserves for additional information regarding the Partnership’s
reserves.
Title to
Properties
The
Partnership holds record title in its name to the working interest in each
well. PDC provides an assignment of working interest for the well
bore prior to the spudding of the well and effective the date of the spudding of
the well, to the Partnership in accordance with the Drilling and Operation
Agreement. Upon completion of the drilling of all of the Partnership
wells, these assignments are recorded in the applicable
county. Investor Partners rely on PDC to use its best judgment to
obtain appropriate title to these working interests. Provisions of
the Agreement relieve PDC from any error in judgment with respect to the waiver
of title defects. PDC takes those steps it deems necessary to assure
that title to the working interests is acceptable for purposes of the
Partnership.
The
Partnership's leases are direct interests in producing acreage. The
Partnership believes it holds good and defensible title to its developed
properties, in accordance with standards generally accepted in the oil and
natural gas industry. As is customary in the industry, a perfunctory
title examination was conducted by PDC at the time the undeveloped properties
were acquired by PDC. Prior to the commencement of drilling operations, a title
examination is conducted and curative work is performed with respect to
discovered defects which are deemed to be significant. Title examinations have
been performed with respect to substantially all of the Partnership's producing
properties.
The
Partnership’s properties are subject to royalty, overriding royalty and other
outstanding interests customary to the industry. The properties may
also be subject to additional burdens, liens or encumbrances customary to the
industry. We do not believe that these burdens, liens or
encumbrances, if any, will materially interfere with the use of the
properties.
|
Item 3.
|
Legal
Proceedings
|
The
Registrant is not currently subject to any material pending legal
proceedings.
See Note
9, Commitments and
Contingencies to the accompanying financial statements for additional
information related to litigation.
|
Item 4.
|
Submission
of Matters to a Vote of Security
Holders
|
None
PART
II
|
Item 5.
|
Market
for Registrant’s Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities
|
At
September 30, 2009, the Partnership had 664 Investor Partners holding 899.94
units and one Managing General Partner. The investments held by the
Investor Partners are in the form of limited partnership
interests. Investor Partners' interests are transferable; however, no
assignee of units in the Partnership can become a substituted partner without
the written consent of the transferor and the Managing General
Partner. As of June 30, 2009, the Managing General Partner has
repurchased 17.02 units of Partnership interests from Investor
Partners.
Market. There is
no public market for the Partnership units nor will a public market develop for
these units in the future. Investor Partners may not be able to sell
their Partnership interests or may be able to sell them only for less than fair
market value. No transfer of a unit may be made unless the transferee
satisfies any relevant suitability requirements, as imposed by law or the
Partnership. The Partnership may require that the transferor provide
an opinion of legal counsel stating that the transfer complies with all
applicable securities laws. A sale or transfer of units by an
individual investor partner requires PDC’s, as Managing General Partner, prior
written consent. For these and other reasons, an individual investor
partner must anticipate that he or she will have to hold his or her partnership
interests indefinitely and will not be able to liquidate his or her investment
in the Partnership. Consequently, an individual investor partner must
be able to bear the economic risk of investing in the Partnership for an
indefinite period of time.
Cash Distribution Policy. PDC plans to
make distributions of Partnership cash on a monthly basis, but no less often
than quarterly, subject to funds being available for
distribution. PDC will make cash distributions of 80% of available
cash to the Investor Partners, adjusted for any units purchased by the Managing
General Partner, and 20% of available cash to the Managing General Partner,
throughout the term of the Partnership. Cash is distributed to the
Investor Partners and PDC as a return of capital in the same proportion as their
interest in the net income of the Partnership.
PDC
cannot presently predict amounts of cash distributions, if any, from the
Partnership. However, PDC expressly conditions any distribution upon
the Partnership having sufficient cash available for
distribution. Sufficient cash available for distribution is defined
to generally mean cash generated by the Partnership in excess of the amount the
Managing General Partner determines is necessary or appropriate to provide for
the conduct of the Partnership's business, to comply with applicable law, to
comply with any other agreements or to provide for future distributions to unit
holders. In this regard, PDC reviews the accounts of the Partnership
at least quarterly for the purpose of determining the sufficiency of
distributable cash available for distribution. Amounts will be paid
to Investor Partners only after payment of fees and expenses to the Managing
General Partner and its affiliates and only if there is sufficient cash
available. The ability of the Partnership to make or sustain cash
distributions depends upon numerous factors. PDC can give no
assurance that any level of cash distributions to the Investor Partners of the
Partnership will be attained, that cash distributions will equal or approximate
cash distributions made to investor partners of prior drilling programs
sponsored by PDC, or that any level of cash distributions can be
maintained. The Partnership made cash distributions of $2,972,261 and
$2,395,447 for the years ended December 31, 2008 and 2007, respectively, and a
total of $17,087,643 since inception.
The
volume of production from producing properties naturally declines with the
passage of time and is not subject to the control of management. The
cash flow generated by the Partnership's activities and the amounts available
for distribution to the Partnership's Investor Partners will, therefore, decline
in the absence of significant increases in the prices that the Partnership
receives for its oil and natural gas production, or significant increases in the
production of oil and natural gas from the successful additional development of
these properties, if any. If the Partnership decides to develop its
wells further, the funds necessary for that development would come from the
Partnership's revenues. As a result, there may be a decrease in the
funds available for distribution, and the distributions to the Investor Partners
may decrease.
Unit Repurchase
Program. Beginning with the third anniversary of the date of
the first cash distribution of the Partnership, Investor Partners of the
Partnership may request the Managing General Partner to repurchase their units.
The Partnership initiated monthly cash distributions to Investor Partners in
February 2005. If requested by individual investor partners, the
Managing General Partner is conditionally obligated to purchase in any calendar
year units which aggregate up to 10% of the initial
subscriptions. Repurchase of units is subject to PDC’s financial
ability to purchase the units. The purchase price will not be less
than four times the most recent twelve months’ cash distributions from
production of the Partnership.
In the
first quarter of 2008, the Managing General Partner repurchased a total of 0.5
units during February 2008, the first month unit repurchases were eligible under
the program, at an average price of $9,230 per unit and 0.25 units during March
2008 at an average price of $7,340 per unit. Second quarter unit
repurchases included the April 2008 repurchase of 0.5 units at an average price
per unit of $7,330 and May 2008 repurchases of 0.25 units at an average price
per unit of $7,520. Remaining 2008 repurchases were comprised of
fourth quarter repurchases of 1.0 unit at an average price of $9,295 per unit in
October and 2.5 units at an average price of $9,748 per unit in
December. First quarter 2009 unit repurchases include 1.0 unit
repurchased at an average price of $10,345 per unit during February and 0.5
units repurchased at an average price of $10,670 per unit during
March. Second quarter repurchases in April 2009, were 4.25 units
repurchased at an average price of $10,794 per unit. There have been
no third quarter unit repurchases through July 2009.
In
addition to the above repurchase program, individual investor partners
periodically offer and PDC repurchases units on a negotiated basis before the
third anniversary of the date of the first cash distribution.
|
Item 6.
|
Selected
Financial Data
|
Not
applicable
|
Item 7.
|
Management’s
Discussion and Analysis of Financial Condition and Results of
Operations
|
The
following discussion and analysis, as well as other sections in this Form 10-K,
should be read in conjunction with the Partnership’s accompanying financial
statements and related notes to the financial statements included in this
report. Further, the Partnership encourages you to revisit Special Note Regarding
Forward-Looking Statements on page 1 of the report.
Overview
The
Partnership was funded on July 2, 2004 with initial contributions of $18.0
million from the Investor Partners and a cash contribution of $4.0 million from
the Managing General Partner. After payment of syndication costs of
$1.8 million and a one-time management fee to PDC of $0.3 million, the
Partnership had available cash of $19.9 million to commence Partnership oil and
natural gas well drilling activities.
The
Partnership began exploration and development activities immediately after
funding. In July 2004, PDC commenced drilling on behalf of the
Partnership. As of December 31, 2008, a total of 23 wells have been
drilled in Colorado, all of which are producing. These 23 wells are
the only wells the Partnership will drill because all of the capital
contributions have been utilized. The completed wells produce
primarily natural gas, with some associated crude oil. Sales of
produced natural gas and oil commenced during the fourth quarter of 2004 as
wells were connected to pipelines. Production and sales increased
through the first two quarters of 2005 as additional wells were completed and
connected to pipelines. As expected for wells in this area, the
Partnership has recognized a steady decline in quarterly production and net
sales. The Partnership’s wells will produce until they are depleted
or until they are uneconomical to produce; however, it is generally, the plan of
the Partnership and the Managing General Partner to recomplete the Codell
formation in certain wells in the Wattenberg Field after five or more years of
production because these wells will have experienced a significant decline in
production in that time period. However, the exact timing of
recompletion may be delayed or accelerated due to changing commodity prices and
the availability of additional geological data and technology. Codell
recompletions typically increase production rates and recoverable
reserves. Although PDC has experienced significant production
increases following prior Codell recompletions, not all such recompletions have
been successful.
2008
Overview
The year
2008 was a year of significant events: oil and natural gas prices reached to
record and near record highs, respectively, through July; then, in the midst of
U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell
to their lowest in four years and natural gas prices decreased approximately
50%. While the Partnership felt the impact of these events, the
Managing General Partner believes the Partnership was successful in managing its
operations in such a manner that the Partnership was able to minimize the
negative price impacts while capitalizing on the positive impacts of price risk
management using derivatives. The Partnership’s derivative position
eased the impact of the fall in oil and natural gas prices. During
2008, the Partnership recorded $0.1 million in net realized derivative
gains. Further, the Partnership estimates the net fair value of its
derivative positions as of December 31, 2008 to be $1.2 million.
The
decline in market prices during the fourth quarter of 2008 resulted in $1.3
million in unrealized gains on derivatives for the year ended December 31,
2008. The $1.3 million in unrealized gains for the year is the fair
value of the derivative positions as of December 31, 2008 of $1.2 million, less
the fair value of derivative positions as of December 31, 2007 of $(0.1)
million. There may be further gains or losses as prices decrease or
increase until the positions mature or are closed.
The
required accounting treatment for derivatives that do not qualify for hedge
accounting treatment under SFAS No. 133 may result in significant swings in
operating results over the life of the derivatives. The combination
of the settled derivative contracts and the revenue received from the oil and
gas sales at delivery are expected to result in a more predictable cash flow
stream and Partnership distributions than would the sales contracts without the
associated derivatives.
The
average NYMEX and CIG prices for the next 24 months (forward curve) from the
respective dates below are as follows:
|
December 31,
|
June 30,
|
December 31,
|
June 30,
|
|||||||||||||||
|
Commodity
|
Index
|
2007
|
2008
|
2008
|
2009
|
|||||||||||||
|
Natural
gas: (per
MMbtu)
|
||||||||||||||||||
|
NYMEX
|
$ | 8.12 | $ | 12.52 | $ | 6.62 | $ | 5.83 | ||||||||||
|
CIG
|
6.78 | 8.86 | 4.49 | 4.87 | ||||||||||||||
|
Oil:
(per
Bbl)
|
NYMEX
|
90.79 | 140.15 | 57.49 | 74.51 | |||||||||||||
The
commodity price declines from June 30, 2008, through December 31, 2008, relative
to the Partnership’s current derivative positions, resulted in the significant
unrealized derivative gains in 2008. If there are further price
declines in 2009, unrealized derivatives gains on our current positions may be
expected to continue. Conversely, if there are price increases in
2009, unrealized derivatives losses on our current positions may be expected to
occur.
Results of
Operations
The
following table sets forth selected information regarding the Partnership’s
results of operations, including production volumes, oil and gas sales, average
sales prices received, average sales price including realized derivative gains
and losses, production and operating costs, depreciation, depletion and
amortization costs, other operating income and expenses for the years ended
December 31, 2008 and 2007.
|
Year
Ended
|
Year
Ended
|
|||||||||||
|
December 31, 2008
|
December 31, 2007
|
Change
|
||||||||||
|
Number
of producing wells (end of period)
|
23 | 23 | - | |||||||||
|
Production: (1)
|
||||||||||||
|
Oil
(Bbl)
|
9,672 | 12,961 | -25 | % | ||||||||
|
Natural
gas (Mcf)
|
446,018 | 463,307 | -4 | % | ||||||||
|
Natural
gas equivalents (Mcfe) (2)
|
504,050 | 541,073 | -7 | % | ||||||||
|
Average
Selling Price (excluding realized gain (loss) on
derivatives)
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 89.15 | $ | 58.04 | 54 | % | ||||||
|
Natural
gas (per Mcf)
|
6.51 | 4.89 | 33 | % | ||||||||
|
Natural
gas equivalents (per Mcfe)
|
7.47 | 5.58 | 34 | % | ||||||||
|
Realized
Gain (Loss) on Derivatives, net
|
||||||||||||
|
Oil
derivatives - realized loss
|
$ | (45,042 | ) | $ | (3,604 | ) | * | |||||
|
Natural
gas derivatives - realized gain
|
115,356 | 175,512 | -34 | % | ||||||||
|
Total
realized gain on derivatives, net
|
$ | 70,314 | $ | 171,908 | -59 | % | ||||||
|
Average
Selling Price (including realized gain (loss) on
derivatives)
|
||||||||||||
|
Oil
(per Bbl)
|
$ | 84.49 | $ | 57.76 | 46 | % | ||||||
|
Natural
gas (per Mcf)
|
6.76 | 5.27 | 28 | % | ||||||||
|
Natural
gas equivalents (per Mcfe)
|
7.61 | 5.90 | 29 | % | ||||||||
|
Average
cost per Mcfe
|
||||||||||||
|
Production
and operating costs (3)
|
$ | 1.79 | $ | 1.44 | 24 | % | ||||||
|
Depreciation,
depletion and amortization
|
2.77 | 2.57 | 8 | % | ||||||||
|
Revenues:
|
||||||||||||
|
Oil
and gas sales
|
$ | 3,763,882 | $ | 3,019,510 | 25 | % | ||||||
|
Oil
and gas price risk management, net
|
1,324,026 | (171,459 | ) | * | ||||||||
|
Total
revenues
|
$ | 5,087,908 | $ | 2,848,051 | 79 | % | ||||||
|
Operating
costs and expenses:
|
||||||||||||
|
Production
and operating costs
|
$ | 901,832 | $ | 776,600 | 16 | % | ||||||
|
Direct
costs - general and administrative
|
102,909 | 49,037 | 110 | % | ||||||||
|
Depreciation,
depletion and amortization
|
1,397,701 | 1,388,803 | 1 | % | ||||||||
|
Accretion
of asset retirement obligations
|
8,780 | 8,304 | 6 | % | ||||||||
|
Total
operating costs and expenses
|
$ | 2,411,222 | $ | 2,222,744 | 8 | % | ||||||
|
Income
from operations
|
$ | 2,676,686 | $ | 625,307 | 328 | % | ||||||
|
Interest
income
|
38,335 | 49,440 | -22 | % | ||||||||
|
Net
income
|
$ | 2,715,021 | $ | 674,747 | 302 | % | ||||||
|
Cash
distributions
|
$ | 2,972,261 | $ | 2,395,447 | 24 | % | ||||||
*
Percentage change not meaningful, equal to or greater than 250% or not
calculable.
|
|
(1)
|
Production
is determined by multiplying the gross production volume of properties in
which we have an interest by the average percentage of the leasehold or
other property interest the Partnership
owns.
|
|
|
(2)
|
A
ratio of energy content of natural gas and oil (six Mcf of natural gas
equals one Bbl of oil) was used to obtain a conversion factor to convert
oil production into equivalent Mcf of natural
gas.
|
|
|
(3)
|
Production
costs represent oil and gas operating expenses which include production
taxes.
|
Definitions
used throughout Management’s Discussion and Analysis of Financial Condition and
Results of Operations.
|
|
·
|
Bbl
– One barrel or 42 U.S. gallons liquid
volume
|
|
|
·
|
MBbl
– One thousand barrels
|
|
|
·
|
Mcf
– One thousand cubic feet
|
|
|
·
|
MMcf
– One million cubic feet
|
|
|
·
|
Mcfe
– One thousand cubic feet of natural gas equivalents, based on a ratio of
6 Mcf for each barrel of oil, which reflects the relative energy
content
|
|
|
·
|
MMcfe
– One million cubic feet of natural gas
equivalents
|
|
|
·
|
MMbtu
– One million British Thermal Units
|
Oil and Natural Gas
Sales
The table
below shows sales and production information for each quarter for the years
ended December 31, 2008 and 2007. Oil and natural gas sales exclude
the impact of commodity-based derivatives, which are reflected in the line “Oil
and gas price risk management, net” in the statements of
operations. (In thousands except for per Mcf, per Bbl and per Mcfe
amounts and percentage changes).
|
2008
|
2007
|
|||||||||||||||||||||||
|
Sales
|
Sales
|
|||||||||||||||||||||||
|
Total
|
(in thousands)
|
MMcfe
|
per Mcfe
|
(in thousands)
|
MMcfe
|
per Mcfe
|
||||||||||||||||||
|
Jan-Mar
|
$ | 954 | 127 | $ | 7.53 | $ | 902 | 156 | $ | 5.79 | ||||||||||||||
|
Apr-Jun
|
1,480 | 158 | 9.35 | 812 | 146 | 5.55 | ||||||||||||||||||
|
Jul-Sept
|
924 | 112 | 8.28 | 655 | 133 | 4.93 | ||||||||||||||||||
|
Oct-Dec
|
406 | 107 | 3.78 | 651 | 106 | 6.13 | ||||||||||||||||||
|
Total
|
$ | 3,764 | 504 | $ | 7.47 | $ | 3,020 | 541 | $ | 5.58 | ||||||||||||||
|
Change
(year over year)
|
25 | % | -7 | % | 34 | % | ||||||||||||||||||
|
2008
|
2007
|
|||||||||||||||||||||||
|
Sales
|
Sales
|
|||||||||||||||||||||||
|
Oil
|
(in thousands)
|
MBbl
|
per Bbl
|
(in thousands)
|
MBbl
|
per Bbl
|
||||||||||||||||||
|
Jan-Mar
|
$ | 194 | 2 | $ | 81.91 | $ | 165 | 4 | $ | 44.60 | ||||||||||||||
|
Apr-Jun
|
290 | 3 | 113.51 | 184 | 3 | 54.20 | ||||||||||||||||||
|
Jul-Sept
|
285 | 3 | 105.95 | 202 | 3 | 64.08 | ||||||||||||||||||
|
Oct-Dec
|
93 | 2 | 45.21 | 201 | 3 | 74.35 | ||||||||||||||||||
|
Total
|
$ | 862 | 10 | $ | 89.15 | $ | 752 | 13 | $ | 58.04 | ||||||||||||||
|
Change
(year over year)
|
15 | % | -25 | % | 54 | % | ||||||||||||||||||
|
2008
|
2007
|
|||||||||||||||||||||||
|
Sales
|
Sales
|
|||||||||||||||||||||||
|
Natural Gas
|
(in thousands)
|
MMcf
|
per Mcf
|
(in thousands)
|
MMcf
|
per Mcf
|
||||||||||||||||||
|
Jan-Mar
|
$ | 760 | 113 | $ | 6.75 | $ | 737 | 133 | $ | 5.52 | ||||||||||||||
|
Apr-Jun
|
1,190 | 143 | 8.32 | 628 | 126 | 4.99 | ||||||||||||||||||
|
Jul-Sept
|
639 | 95 | 6.70 | 453 | 114 | 3.98 | ||||||||||||||||||
|
Oct-Dec
|
313 | 95 | 3.29 | 450 | 90 | 5.00 | ||||||||||||||||||
|
Total
|
$ | 2,902 | 446 | $ | 6.51 | $ | 2,268 | 463 | $ | 4.89 | ||||||||||||||
|
Change
(year over year)
|
28 | % | -4 | % | 33 | % | ||||||||||||||||||
The 25%
increase in total sales in 2008 as compared to 2007 was due to an increase in
average sales price per Mcfe of 34% partially offset by decreased total
production volumes, in Mcfe or energy equivalency basis, of 7%.
Commodity
price increases during the first half of 2008, which contributed to an increase
in sales of $0.9 million, were partially offset by sales declines of $0.2
million due to decreased production volumes, resulting in the overall $0.7
million increase in oil and natural gas sales in 2008 as compared to
2007. This decline in production volumes is consistent with the
historically declining production curves for wells drilled in the Wattenberg and
Piceance fields. The year-to-year decrease in both oil and natural
gas production volumes of 25% and 4%, respectively, reflects the historically
steeper decline in oil production volumes during the earlier portions of the
production life cycle as compared to natural gas which was offset, however, by a
more substantial increase in oil prices (54%) than natural gas prices (33%)
during the period.
On a
quarterly basis, production volumes, on an energy equivalency basis, declined
during the quarters ended March 31 and September 30, 2008, compared to the same
periods in 2007. However, commodity price increases of $0.2 million
and $0.4 million, respectively, offset production volume declines of $0.2
million and $0.1 million, respectively, so that overall sales remained unchanged
and increased by $0.3 million, respectively, during these periods. During the
quarter ended June 30, production increased due to a decrease in line pressure
as new pipeline was added and more efficient routing of the gas was effected by
Williams. This resulted in a production increase of $0.1 million and
combined with commodity price increases of $0.6 million over the previous year’s
comparable period, resulted in that quarter’s overall oil and natural gas sales
increase of $0.7 million.
Overall
quarterly sales declined, however, by $0.3 million, during the quarter ended
December 31, 2008 over the previous year’s fourth quarter, due to commodity
price reductions of $0.3 million while production volumes remained substantially
unchanged period-to-period.
The
Partnership expects to experience continued declines in both oil and natural gas
production volumes over the wells’ life cycles until such time that the
Wattenberg wells may be successfully recompleted. Subsequent to
successful recompletion, if any, production will once again begin to
decline.
Oil and Natural Gas
Pricing
Financial
results depend upon many factors, particularly the prices of oil and natural gas
and our ability to market our production effectively. Natural gas and
oil prices have been among the most volatile of all commodity
prices. These price variations have a material impact on Partnership
financial results. Natural gas and oil prices also vary by region and
locality, especially in the Rocky Mountain Region, depending upon the distance
to markets, and the supply and demand relationships in that region or
locality. This can be especially true in the Rocky Mountain Region in
which all of the Partnership’s wells are located. The combination of
increased drilling activity and the lack of substantial local market demand can
result in a local market oversupply situation from time to time. The
Managing General Partner believes such a situation existed in the Rocky Mountain
Region during 2007, with production exceeding the local market demand and
pipeline transportation capacity to non-local markets. The result,
beginning in the second quarter of 2007 and continuing into the fourth quarter
of 2007, was a decrease in the price of Rocky Mountain natural gas as
measured by the Colorado Interstate Gas, or CIG, Index (per MMbtu) compared to
the New York Mercantile Exchange, or NYMEX, price (per MMbtu).
The
expansion in January 2008 of the Rockies Express pipeline (“REX”), a major
interstate pipeline constructed and operated by a non-affiliated entity,
resulted in a narrowing of the NYMEX and CIG price differential to under $1.00
between the indices’ average prices in January and February
2008. However, a substantial portion of the new capacity created by
the REX Pipeline is now under contract resulting in a resumption of regional
transportation capacity restraints and a widening of the NYMEX-CIG differential
that peaked in June and September at average index price differentials of $4.58
and $4.00, respectively. Index differentials closed 2008 having again
narrowed to $1.30, and are expected to average $0.96 for the next 24 months
(forward curve) based on index futures. Like most producers in the
region, the Partnership relies on major interstate pipeline companies to
construct these facilities to increase pipeline capacity, rendering the timing
and availability of these facilities beyond the Partnership’s
control. In view of the regional transportation capacity issues cited
herein regarding Rocky Mountain region production, the Partnership believes that
the cited capacity constraints will continue into the future and that the sale
of production in the Rocky Mountain Region will continue to be governed by
price. To that end, the Partnership has been able to sell all of its
production to date, has not had to significantly curtail its production for long
periods of time because of an inability to sell its production because of
pipeline unavailability and believes that it will be able to sell all of its
future production at market prices.
Oil
pricing is also driven strongly by supply and demand
relationships. In the Rocky Mountain Region for 2008, Partnership oil
sales averaged $89.15 per barrel which is below the NYMEX oil market 12-month
average monthly closing prices (per Barrel) for 2008 of $104.42, due to supply
competition from other Rocky Mountain oil and Canadian oil that has driven down
market prices.
The price
the Partnership receives for the natural gas produced in the Rocky Mountain
Region is based on a market basket of prices, which primarily includes natural
gas sold at the CIG prices with a portion sold at Mid-Continent, San Juan Basin,
Southern California or other nearby region prices. The CIG Index, and
other indices for production delivered to other Rocky Mountain pipelines, has
historically been less than the price received for natural gas produced in the
eastern regions, which is NYMEX based.
Through
September 2009, oil and natural gas prices have continued to fluctuate, with oil
prices on NYMEX as high as $74.37 (per Barrel) on August 24, 2009 and as low as
$33.98 (per Barrel) on February 12, 2009 and natural gas prices on CIG as high
as $4.59 (per MMbtu) on January 7, 2009 and as low as $1.33 (per MMbtu) on April
14, 2009.
Oil and Natural Gas Price
Risk Management, Net
The
Managing General Partner uses oil and natural gas commodity derivative
instruments to manage price risk for PDC as well as its sponsored drilling
partnerships. The Managing General Partner sets these instruments for
PDC and the various partnerships managed by PDC jointly by area of
operations. Prior to September 30, 2008, as production volumes
changed, the allocation of derivative positions between PDC’s corporate
interests and each of the sponsored drilling partnerships changed on a pro-rata
basis. As of September 30, 2008, PDC has fixed the allocation of
derivative positions, between PDC and each partnership. Existing positions are
allocated based on fixed quantities for each position and new positions will
have specific designations relative to the applicable
partnership. Realized and unrealized gains and losses resulting from
derivative positions are reported on the statement of operations as “Oil and gas
price risk management, net.” The net gains/losses are comprised of
the change in fair value of derivative positions related to the Partnership’s
production and underlying derivative contracts entered into by the Managing
General Partner on behalf of the Partnership.
In
periods of rising prices, the Partnership will generally record losses on its
derivative positions as fair values exceed contract prices determining the
Partnership’s oil and natural gas sales. Conversely, in periods of
decreasing prices, the Partnership will generally recognize gains on its
derivative positions. During 2008, the Partnership experienced
volatility in oil and gas prices that resulted in fluctuation in both realized
and unrealized derivative positions.
The
following table presents the realized and unrealized gains and losses recorded
for each of the quarterly and annual periods identified:
|
Three months ended
|
||||||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
Total
|
||||||||||||||||
|
Realized
gains (losses)
|
||||||||||||||||||||
|
Oil
|
$ | (10,885 | ) | $ | (45,232 | ) | $ | (37,585 | ) | $ | 48,660 | $ | (45,042 | ) | ||||||
|
Natural
gas
|
(24,010 | ) | (237,628 | ) | 75,399 | 301,595 | 115,356 | |||||||||||||
|
Realized
(loss) gain
|
(34,895 | ) | (282,860 | ) | 37,814 | 350,255 | 70,314 | |||||||||||||
|
Unrealized
(loss) gain
|
(363,931 | ) | (566,693 | ) | 1,627,955 | 556,381 | 1,253,712 | |||||||||||||
|
Oil
and gas price risk management, net
|
$ | (398,826 | ) | $ | (849,553 | ) | $ | 1,665,769 | $ | 906,636 | $ | 1,324,026 | ||||||||
|
Three months ended
|
||||||||||||||||||||
|
March 31, 2007
|
June 30, 2007
|
September 30, 2007
|
December 31, 2007
|
Total
|
||||||||||||||||
|
Realized
gains (losses)
|
||||||||||||||||||||
|
Oil
|
$ | (1,422 | ) | $ | (1,552 | ) | $ | (449 | ) | $ | (181 | ) | $ | (3,604 | ) | |||||
|
Natural
gas
|
(6,228 | ) | 53,992 | 99,166 | 28,582 | 175,512 | ||||||||||||||
|
Realized
(loss) gain
|
(7,650 | ) | 52,440 | 98,717 | 28,401 | 171,908 | ||||||||||||||
|
Unrealized
(loss) gain
|
(141,498 | ) | 54,023 | (21,128 | ) | (234,764 | ) | (343,367 | ) | |||||||||||
|
Oil
and gas price risk management, net
|
$ | (149,148 | ) | $ | 106,463 | $ | 77,589 | $ | (206,363 | ) | $ | (171,459 | ) | |||||||
“Oil and
gas price risk management, net” includes realized gains and losses and
unrealized changes in the fair value of oil and natural gas derivatives related
to Partnership oil and natural gas production. See and Note 4, Fair Value of Financial
Instruments and Note 5, Derivative Financial
Instruments, to the accompanying financial statements for additional
details of the Partnership’s derivative financial instruments.
For the
year ended December 31, 2008, the Partnership recorded realized gains of $0.1
million and unrealized gains of $1.2 million, resulting in a net $1.3 million
gain for the year. During the quarter ended March 31, 2008, prices
increased and remained above December 31, 2007 prices resulting in unrealized
losses of $0.4 million. The CIG-index monthly average of daily
natural gas prices (per MMbtu) and oil prices on NYMEX (per barrel) in the
second quarter 2008 remained above December 31, 2007 levels, resulting in the
$0.3 million realized and $0.6 million unrealized losses for that period.
Although Rocky Mountain Region oil and natural gas prices increased during the
first seven months of 2008, the Partnership experienced significant commodity
price declines during the last five months of 2008, relative to the
Partnership’s current derivative positions, which resulted in significant
unrealized derivative gains for the year and for the quarters ended September 30
and December 31. Monthly averages of daily natural gas prices for the
months August through December declined in August to $5.45 and retrenched
further to a low during October of $2.90. Oil prices experienced a
steep decline from a July 2008 high of $145.29 to $44.60 at December 31,
2008. This pricing pattern in the Rocky Mountain Region for oil and
natural gas resulted in the Partnership’s third quarter unrealized gains of $1.7
million and fourth quarter realized and unrealized gains of $0.4
million and $0.5 million, respectively. When forward prices for oil
and natural gas decrease as they did throughout the last five months of 2008,
the Partnership’s derivative positions, which include floors, ceilings and
swaps, tend to increase in value, resulting in unrealized gain
positions.
In 2007,
the Partnership incurred a realized gain of $0.2 million and an unrealized loss
of $0.4 million, resulting in a $0.2 million net loss for the
year. The majority of the unrealized losses recognized for 2007 and
for the quarters ended March 31 and December 31, respectively, were due to
increasing natural gas prices. The decline in the CIG market during
the second and third quarters of 2007, which fell to a low of $1.05 for the
September average of natural gas daily prices (per MMbtu), resulted in the
realized gain during 2007. When forward prices for oil and natural
gas prices increase as they did in 2007, the Partnership’s derivative portfolio
tends to decrease in value, resulting in unrealized loss
positions. Due to the continued volatility of commodity prices, large
quarter to quarter fluctuations in “Oil and gas price risk management, net”
occur.
Oil and Natural Gas Sales Derivative
Instruments. The Managing General Partner uses various
derivative instruments to manage fluctuations in oil and natural gas
prices. The Managing General Partner has in place a series of
collars, fixed price swaps and basis protection swaps on a portion of the
Partnership’s oil and natural gas production, as set forth in the following
table.
This
table identifies the Partnership’s derivative positions related to oil and gas
sales activities in effect as of June 30, 2009, on the Partnership’s
production.
|
Collars
|
Fixed-Price
Swaps
|
Basis
Protection Swaps
|
||||||||||||||||||||||||||||||||||
|
Floors
|
Ceilings
|
|||||||||||||||||||||||||||||||||||
|
Weighted
|
Weighted
|
Weighted
|
Weighted
|
Fair
Value
|
||||||||||||||||||||||||||||||||
|
Commodity/
|
Quantity
|
Average
|
Quantity
|
Average
|
Quantity
|
Average
|
Quantity
|
Average
|
at
|
|||||||||||||||||||||||||||
|
Operating
Area/
|
(Gas-MMbtu
|
Contract
|
(Gas-MMbtu
|
Contract
|
(Gas-MMbtu
|
Contract
|
(Gas-MMbtu
|
Contract
|
June 30,
|
|||||||||||||||||||||||||||
|
Index
|
Oil-Bbls)
|
Price
|
Oil-Bbls)
|
Price
|
Oil-Bbls)
|
Price
|
Oil-Bbls)
|
Price
|
2009
|
|||||||||||||||||||||||||||
|
Natural
Gas
|
||||||||||||||||||||||||||||||||||||
|
Rocky
Mountain Region
|
||||||||||||||||||||||||||||||||||||
|
CIG
|
||||||||||||||||||||||||||||||||||||
|
3Q
2009
|
75,689 | $ | 5.75 | 75,689 | $ | 8.90 | - | $ | - | - | $ | - | $ | 225,647 | ||||||||||||||||||||||
|
4Q
2009
|
53,256 | 6.67 | 53,256 | 10.21 | 19,688 | 9.20 | - | - | 262,375 | |||||||||||||||||||||||||||
|
2010
|
61,366 | 6.63 | 61,366 | 10.79 | 29,531 | 9.20 | 181,049 | 1.88 | 70,475 | |||||||||||||||||||||||||||
|
2011
|
28,989 | 4.75 | 28,989 | 9.45 | - | - | 215,684 | 1.88 | (189,872 | ) | ||||||||||||||||||||||||||
|
2012
|
- | - | - | - | - | - | 227,950 | 1.88 | (189,981 | ) | ||||||||||||||||||||||||||
|
2013
|
- | - | - | - | - | - | 211,754 | 1.88 | (159,416 | ) | ||||||||||||||||||||||||||
|
NYMEX
|
||||||||||||||||||||||||||||||||||||
|
2010
|
7,747 | 5.75 | 7,747 | 8.30 | 160,968 | 5.62 | - | - | (57,737 | ) | ||||||||||||||||||||||||||
|
2011
|
10,537 | 5.75 | 10,537 | 8.30 | 58,166 | 6.96 | - | - | 592 | |||||||||||||||||||||||||||
|
2012
|
- | - | - | - | 61,041 | 6.96 | - | - | (11,549 | ) | ||||||||||||||||||||||||||
|
Total
Natural Gas
|
(49,466 | ) | ||||||||||||||||||||||||||||||||||
|
Oil
|
||||||||||||||||||||||||||||||||||||
|
Rocky
Mountain Region
|
||||||||||||||||||||||||||||||||||||
|
NYMEX
|
||||||||||||||||||||||||||||||||||||
|
3Q
2009
|
- | - | - | - | 1,414 | 90.52 | - | - | 27,549 | |||||||||||||||||||||||||||
|
4Q
2009
|
- | - | - | - | 1,414 | 90.52 | - | - | 24,913 | |||||||||||||||||||||||||||
|
2010
|
- | - | - | - | 4,906 | 92.96 | - | - | 84,957 | |||||||||||||||||||||||||||
|
Total
Oil
|
137,419 | |||||||||||||||||||||||||||||||||||
|
Total
Natural Gas and Oil
|
$ | 87,953 | ||||||||||||||||||||||||||||||||||
In July
2009, the Managing General Partner entered into a NYMEX-based oil swap covering
approximately 50% of the Partnership’s estimated production of oil for the
calendar year 2011 at $70.75 per barrel.
Production and Operating
Costs
Production
and Operating Costs include production taxes and transportation costs which vary
with revenues and production, well operating costs charged on a per well basis
and other direct costs incurred in the production process.
|
2008
|
2007
|
|||||||||||||||||||||||
|
Prod Costs
|
Mcfe
|
per Mcfe
|
Prod Costs
|
Mcfe
|
per Mcfe
|
|||||||||||||||||||
|
Jan-Mar
|
$ | 191,687 | 126,681 | $ | 1.51 | $ | 195,397 | 155,517 | $ | 1.26 | ||||||||||||||
|
Apr-Jun
|
295,585 | 158,382 | 1.87 | 193,665 | 146,279 | 1.32 | ||||||||||||||||||
|
Jul-Sep
|
224,979 | 111,504 | 2.02 | 208,557 | 132,937 | 1.57 | ||||||||||||||||||
|
Oct-Dec
|
189,581 | 107,483 | 1.76 | 178,981 | 106,340 | 1.68 | ||||||||||||||||||
|
Total
|
$ | 901,832 | 504,050 | $ | 1.79 | $ | 776,600 | 541,073 | $ | 1.44 | ||||||||||||||
As
production declines as per the historical decline curve, fixed costs may
increase as a percentage of total costs. This results in production
costs per unit increases. As production is expected to continue to
decline, production costs per unit can be expected to increase.
Generally,
production and operating costs vary either with total oil and natural gas sales
or production volumes. Property and severance taxes are estimates by
the Managing General Partner based on rates determined using historical
information. These amounts are subject to revision based on actual
amounts determined during future filings by the Managing General Partner with
the taxing authorities. Property and severance taxes vary directly
with total oil and natural gas sales. Transportation costs vary
directly with production volumes. Fixed monthly well operating costs
increase on a per unit basis as production decreases per the historical decline
curve. In addition, general oil field services and all other costs
vary and can fluctuate based on services required. These costs
include water hauling and disposal, equipment repairs and maintenance, snow
removal and service rig workovers. In addition, general oil field
service costs have experienced significant inflationary increases.
During
2008, production and operating costs increased $0.1 million or 16% compared to
the previous year, due primarily to variable costs, including production-related
taxes and transportation, related to oil and natural gas volume reductions, on
an Mcfe or energy equivalency basis, of 7%. Increases in the cost of
general oil field services, including increased road maintenance and equipment
repairs, are reflected in the per Mcfe basis unit cost increases for the second
and third quarters of 2008. A decrease in general oil field service
costs caused the reduction in the per Mcfe basis unit cost during the fourth
quarter of 2008.
An
increase in general oil field service costs caused the increase in the per Mcfe
basis unit cost during the first quarter of 2007. The increases in
the per Mcfe basis unit costs through the remaining three quarters of 2007 were
principally due to production volume decreases.
Direct Costs – General and
Administrative
Direct
costs – general and administrative consist primarily of professional fees for
financial statement audits, income tax return preparation and legal
matters. Direct costs increased during 2008 by approximately $54,000
due primarily to increases in audit fees of approximately $23,000 and outside
professional fees of approximately $46,000 offset by a reduction in legal fees
of approximately $13,000.
Depreciation, Depletion and
Amortization
The
Partnership recorded depreciation, depletion, and amortization (“DD&A”)
expense in 2008 and 2007 as follows:
|
2008
|
2007
|
|||||||||||||||||||||||
|
DD&A
|
Mcfe
|
per Mcfe
|
DD&A
|
Mcfe
|
per Mcfe
|
|||||||||||||||||||
|
Jan-Mar
|
$ | 338,689 | 126,681 | $ | 2.67 | $ | 389,979 | 155,517 | $ | 2.51 | ||||||||||||||
|
Apr-Jun
|
394,122 | 158,382 | 2.49 | 360,868 | 146,279 | 2.47 | ||||||||||||||||||
|
Jul-Sep
|
318,593 | 111,504 | 2.86 | 319,661 | 132,937 | 2.40 | ||||||||||||||||||
|
Oct-Dec
|
346,297 | 107,483 | 3.22 | 318,295 | 106,340 | 2.99 | ||||||||||||||||||
|
Total
|
$ | 1,397,701 | 504,050 | $ | 2.77 | $ | 1,388,803 | 541,073 | $ | 2.57 | ||||||||||||||
DD&A
expense is primarily based upon year-end proved developed producing oil and gas
reserves. These reserves are valued at the price of oil and natural gas as of
December 31 each year. If prices increase, the corresponding volume
of oil and natural gas reserves will increase, resulting in decreases in the
rate of DD&A per unit of production. If year-end prices decrease
as they did from 2007 to 2008, volumes of oil and natural gas reserves will
decline, resulting in increases in the rate of DD&A per unit of
production.
DD&A
expense for the year 2008 compared to 2007 remained substantially unchanged
primarily due to the production level decrease of $0.1 million which was offset
by an increase per Mcfe due to somewhat lower reserves at December 31,
2008. In both the fourth quarter of 2008 and 2007, the DD&A unit
cost per Mcfe increased due to revised estimates of reserves from the annual
reserve reports which indicated decreases in proved developed reserves from the
respective prior periods. While both production and overall year-end
reserves are expected to decline gradually year-to-year over the wells’
remaining life cycles, downward revisions to oil and natural gas reserves in the
annual 2008 reserve report resulted in the larger DD&A unit cost increase
during the fourth quarter of 2008 as compared to the fourth quarter
2007.
The
variances in the per Mcfe rates for the 2008 quarters ended March 31, June 30
and September 30 and the comparable quarter for 2007 are primarily the result of
the changing production mix between the Partnership’s Wattenberg and Grand
Valley fields which have significantly different DD&A rates.
Interest
Income
Interest
income decreased in 2008 as compared to 2007 due to the somewhat lower level of
undistributed revenues held by the Managing General Partner, as well as a
reduction in the interest rates applied to those undistributed revenue
amounts. Additionally, interest rates decreased on amounts held in
escrow by the Managing General Partner on behalf of the Partnership related to
production tax obligation over-withholding during the years prior to
2007. For more information on the production tax obligation
over-withholding by the Managing General Partner, see Note 2, Summary of Significant Accounting
Policies−Due from (to) Managing General Partner−Other.
Liquidity and Capital
Resources
As the
Partnership completed its drilling activities as of March 31, 2005, the
Partnership’s operations are expected to be conducted with available funds and
revenues generated from oil and natural gas production activities. Because oil
and gas production from the Partnership’s existing properties declined rapidly
in the first two years, the Partnership may be unable to maintain its current
level of oil and gas production and cash flows from operations if commodity
prices remain in their current depressed state for a prolonged period beyond
2009. This decreased production would have a material negative impact
on the Partnership’s operations and may result in reduced cash distributions to
the Investor Partners in 2010 and beyond. Based on the current economic
environment, the Managing General Partner has no immediate plans to initiate
recompletion activities in the Codell formation of the Wattenberg Field
wells. The Managing General Partner will re-evaluate the feasibility
of commencing these recompletion activities as economic conditions
improve. However, no assurance can be given that recompletion
activities will be feasible.
The
Partnership’s liquidity may be impacted by fluctuating oil and natural gas
prices, as noted in Item 1A, Risk
Factors. Changes in market prices for oil and natural gas
directly affect the level of cash flow from operations. While a
decline in oil and natural gas prices would affect the amount of cash flow that
would be generated from operations, the Partnership had oil and natural gas
derivatives in place as of June 30, 2009, covering 71% of the Partnership’s
expected oil production and 79% of its expected natural gas production for the
remainder of 2009. These contracts reduce the impact of price changes
for a substantial portion of the Partnership’s 2009 cash from
operations. In July 2009, the Managing General Partner entered into a
NYMEX-based oil swap covering approximately 50% of the Partnership’s estimated
production of oil for the calendar year 2011 at $70.75 per
barrel. The fair value of the current derivatives positions will
change based on changes in oil and natural gas futures markets. Oil
and natural gas derivatives as of December 31, 2008 are detailed in Note 5,
Derivative Financial
Instruments to the accompanying financial statements.
Working
Capital
The
following table sets forth the working capital position of the
Partnership:
|
As of
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
Working
capital
|
$ | 1,127,939 | $ | 1,012,126 | $ | 1,929,827 | $ | 2,190,481 | ||||||||
|
As of
|
||||||||||||||||
|
March 31, 2007
|
June 30, 2007
|
September 30, 2007
|
December 31, 2007
|
|||||||||||||
|
Working
capital
|
$ | 1,450,306 | $ | 1,503,645 | $ | 1,421,595 | $ | 1,155,245 | ||||||||
Cash
Flows From Financing and Investing Activities
In 2008,
the Partnership received a refund of approximately $37,000 from the State of
Colorado for state sales taxes charged during prior years on well tubing and
casing purchases during the Partnership’s drilling operations, which were
subsequently determined to be tax-exempt utilization of this
material. The Partnership has from time-to-time, invested in
additional equipment which supports enhanced hydrocarbon recovery, treatment,
delivery and measurement or environmental protection, which totaled
approximately $8,000 in 2008.
The
Partnership initiated monthly cash distributions to investors in February 2005
and has distributed $17.1 million of its operating cash flows from its July 2,
2004 date of inception through December 31, 2008. The following table
sets forth the quarterly cash distributions to the Managing General Partner and
the Investor Partners during the years ended December 31, 2008 and 2007,
respectively.
|
Managing
|
Investor
|
|||||||||||
|
General
Partner
|
Partners
|
Total
|
||||||||||
|
Distributions
|
Distributions
|
Distributions
|
||||||||||
|
2008
|
||||||||||||
|
Jan-Mar
|
$ | 98,574 | $ | 394,299 | $ | 492,873 | ||||||
|
Apr-Jun
|
148,380 | 593,522 | 741,902 | |||||||||
|
Jul-Sep
|
196,122 | 784,490 | 980,612 | |||||||||
|
Oct-Dec
|
151,375 | 605,499 | 756,874 | |||||||||
| $ | 594,451 | $ | 2,377,810 | $ | 2,972,261 | |||||||
|
2007
|
||||||||||||
|
Jan-Mar
|
$ | 129,948 | $ | 519,794 | $ | 649,742 | ||||||
|
Apr-Jun
|
118,300 | 492,530 | 610,830 | |||||||||
|
Jul-Sep
|
123,010 | 492,043 | 615,053 | |||||||||
|
Oct-Dec
|
103,964 | 415,858 | 519,822 | |||||||||
| $ | 475,222 | $ | 1,920,225 | $ | 2,395,447 | |||||||
Cash
Flows From Operating Activities
Net cash
provided by operating activities was $3.0 million in 2008 compared to $2.4
million in 2007, an increase of $0.6 million. The increase in cash
provided by operating activities was due primarily to the
following:
|
|
·
|
An
increase in oil and gas sales revenues of 25% offset by a $0.1 million
decrease in realized oil and gas price risk management gains, net; an
increase in production and operating costs of 16% and an increase in
direct costs of approximately
$54,000.
|
|
|
·
|
Increase
in the “Due from (to) Managing General Partner,
net.”
|
The
following table presents the operating cash flows for the following
periods:
|
2008
|
||||||||||||||||
|
Quarter
ended
|
Quarter
ended
|
Quarter
ended
|
Quarter
ended
|
|||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
|||||||||||||
|
Cash
flows from operating activities
|
$ | 501,665 | $ | 744,152 | $ | 984,395 | $ | 760,352 | ||||||||
|
2007
|
||||||||||||||||
|
Quarter
ended
|
Quarter
ended
|
Quarter
ended
|
Quarter
ended
|
|||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
|||||||||||||
|
Cash
flows from operating activities
|
$ | 654,524 | $ | 614,471 | $ | 618,547 | $ | 519,731 | ||||||||
Information
related to the oil and gas reserves of the Partnership’s wells is discussed in
detail in Supplemental Oil & Gas Information – Unaudited, Net Proved Oil and Gas
Reserves.
Contractual Obligations and
Contingent Commitments
The table
below sets forth the Partnership’s contractual obligations and contingent
commitments as of December 31, 2008 and 2007.
|
Payments due by period
|
||||||||||||||||||||
|
Contractual
Obligations and
|
Less
than
|
More
than
|
||||||||||||||||||
|
Contingent Commitments
|
Total
|
1 year
|
1-3 years
|
3-5 years
|
5 years
|
|||||||||||||||
|
December 31, 2008
|
||||||||||||||||||||
|
Unrealized
loss on derivative contracts
|
$ | 100,327 | $ | - | $ | - | $ | 100,327 | $ | - | ||||||||||
|
Asset
Retirement Obligations
|
161,487 | - | - | - | 161,487 | |||||||||||||||
| $ | 261,814 | $ | - | $ | - | $ | 100,327 | $ | 161,487 | |||||||||||
|
December 31, 2007
|
||||||||||||||||||||
|
Unrealized
loss on derivative contracts
|
$ | 68,645 | $ | 68,645 | $ | - | $ | - | $ | - | ||||||||||
|
Asset
Retirement Obligations
|
152,707 | - | - | - | 152,707 | |||||||||||||||
| $ | 221,352 | $ | 68,645 | $ | - | $ | - | $ | 152,707 | |||||||||||
Critical Accounting Policies
and Estimates
The
Managing General Partner has identified the following accounting policies as
critical to the understanding of the results of the operations of the
Partnership. This is not a comprehensive list of all of the
Partnership’s accounting policies. In many cases, the accounting
treatment of a particular transaction is specifically dictated by accounting
principles generally accepted in the United States, with no need for
management's judgment in their application. There are also areas in
which management's judgment in selecting any available alternative would not
produce a materially different result. However, certain accounting policies are
important to the portrayal of the Partnership's financial condition and results
of operations and require management's most subjective or complex judgments, and
as a result, are subject to an inherent degree of uncertainty. In
applying those policies, management uses its judgment to determine the
appropriate assumptions to be used in the determination of certain
estimates. Those estimates are based on historical experience,
observance of trends in the industry, and information available from other
outside sources, as appropriate. For a more detailed discussion on
the application of these and other accounting policies, see Note 2, Summary of Significant Accounting
Policies in the accompanying financial statements. The
Partnership's critical accounting policies and estimates are as
follows:
Oil
and Natural Gas Properties
The
Partnership accounts for its oil and natural gas properties under the successful
efforts method of accounting. Costs of proved developed producing
properties, successful exploratory wells and development dry hole costs are
depreciated or depleted by the unit-of-production method based on estimated
proved developed oil and natural gas reserves. Property acquisition
costs are depreciated or depleted on the unit-of-production method based on
estimated proved oil and natural gas reserves.
The
Partnership’s estimates of proved reserves are based on quantities of oil and
gas that engineering and geological analysis demonstrates, with reasonable
certainty, to be recoverable from established reservoirs in the future under
current operating and economic conditions. Annually, we engage independent
petroleum engineers to prepare a reserve and economic evaluation of all our
properties on a well-by-well basis as of December 31.
Proved
reserves are the estimated quantities of oil and natural gas that geologic and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either positively or
negatively, as additional information becomes available and as contractual,
economic and political conditions change. The Partnership’s net proved reserve
estimates have been adjusted as necessary to reflect all contractual agreements,
royalty obligations and interests owned by others at the time of the
estimate.
Proved
developed reserves are the quantities of oil and natural gas expected to be
recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves are those reserves expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for completion. In some cases, proved
undeveloped reserves may require substantial new investments in additional wells
and related facilities.
The
process of estimating and evaluating oil and gas reserves is complex, requiring
significant decisions in the evaluation of available geological, geophysical,
engineering and economic data. The data for a given property may also change
substantially over time as a result of numerous factors, including additional
development activity, evolving production history and a continual reassessment
of the viability of production under changing economic conditions. As a result,
revisions in existing reserve estimates occur from time to time. Although every
reasonable effort is made to ensure that reserve estimates reported represent
our most accurate assessments possible, the subjective decisions and variances
in available data for various properties increase the likelihood of significant
changes in these estimates over time. Because estimates of reserves
significantly affect DD&A expense, a change in estimated reserves could have
a material effect on the Partnership’s financial statements.
In
accordance with Statement of Financial Accounting Standards, SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Partnership assesses its proved oil
and gas properties for possible impairment, upon a triggering event, by
comparing net capitalized costs to estimated undiscounted future net cash flows
on a field-by-field basis using estimated future production based upon prices at
which the Partnership reasonably estimates the commodity to be
sold. The estimates of future prices may differ from current market
prices of oil and natural gas. Downward revisions in estimates to the
Partnership’s reserve quantities, expectations of falling commodity prices or
rising operating costs could result in a triggering event and therefore a
possible impairment of the Partnership’s oil and natural gas
properties. If net capitalized costs exceed undiscounted future net
cash flows, impairment is based on estimated fair value utilizing a future
discounted cash flow analysis and is measured by the amount by which the net
capitalized costs exceed their fair value. Due to the significant
reduction in oil and natural gas prices during the fourth quarter of 2008 and
the availability of new reserve information, the Partnership reviewed its proved
oil and natural gas properties for impairment at December 31,
2008. The Partnership did not incur any impairment loss as a result
of this review. Although cash flow estimates used by the Partnership
are based on the relevant information available at the time the estimates are
made, estimates of future cash flows are, by nature, highly uncertain and may
vary significantly from actual results.
Revenue
Recognition
Sales of
natural gas are recognized when natural gas has been delivered to a custody
transfer point, persuasive evidence of a sales arrangement exists, the rights
and responsibility of ownership pass to the purchaser, collection of revenue
from the sale is reasonably assured, and the sales price is fixed or
determinable. Natural gas upon delivery is sold by the Managing
General Partner under contracts with terms ranging from one month up to the life
of the well. Virtually all of the Managing General Partner’s
contracts’ pricing provisions are tied to a market index with certain
adjustments based on, among other factors, whether a well delivers to a
gathering or transmission line, quality of gas and prevailing supply and demand
conditions, so that the price of the natural gas fluctuates to remain
competitive with other available natural gas supplies. As a result,
the Partnership’s revenues from the sale of natural gas will suffer if market
prices decline and benefit if they increase. The Managing General
Partner may from time to time enter into derivative agreements which may either
“swap” or “collar” a price range or provide for basis protection in order to
reduce the impact of market price fluctuations. The Partnership believes that
the pricing provisions of its natural gas contracts are customary in the
industry.
The
Partnership currently uses the “Net-Back” method of accounting for
transportation arrangements of natural gas sales. The Managing
General Partner sells natural gas at the wellhead, collects a price, and
recognizes revenues based on the wellhead sales price since transportation costs
downstream of the wellhead are incurred by the Partnership’s customers and
reflected in the wellhead price.
Sales of
oil are recognized when persuasive evidence of a sales arrangement exists, the
oil is verified as produced and is delivered from storage tanks at well
locations to a purchaser, collection of revenue from the sale is reasonably
assured, and the sales price is determinable. The Partnership does
not refine any of its oil production. The Partnership’s crude oil
production is sold to purchasers at or near the Partnership’s wells under
short-term purchase contracts at prices and in accordance with arrangements that
are customary in the oil industry.
Fair
Value Measurements
The
Partnership adopted the provisions of Statement of SFAS No. 157, Fair Value Measurements,
effective January 1, 2008. SFAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands disclosures related
to fair value measurements. SFAS No. 157 applies broadly to financial and
nonfinancial assets and liabilities that are measured at fair value under other
authoritative accounting pronouncements, but does not expand the application of
fair value accounting to any new circumstances. In February 2008, the
Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”)
FAS No. 157-2, Effective Date
of FASB Statement No. 157, which delayed the effective date of SFAS No.
157 by one year (to January 1, 2009) for nonfinancial assets and liabilities,
except those that are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). Nonfinancial
assets and liabilities for which the Partnership has not applied the provisions
of SFAS No. 157 include those initially measured at fair value, including the
Partnership’s asset retirement obligations.
Determination of Fair Value.
The Partnership determines the fair value of its assets and liabilities, unless
specifically excluded, pursuant to FAS No. 157. FAS No. 157 defines
fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date.
FAS No.
157 establishes a fair value hierarchy that requires an entity to maximize the
use of observable inputs and minimize the use of unobservable inputs when
measuring fair value. The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3). In
some cases, the inputs used to measure fair value might fall in different levels
of the fair value hierarchy. The lowest level input that is
significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy. Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or liability and
may affect the valuation of the assets and liabilities and their placement
within the fair value hierarchy levels. The three levels of inputs
that may be used to measure fair value are defined as:
Level 1 –
Quoted prices (unadjusted) in active markets for identical assets or
liabilities. Included in Level 1 would be commodity derivative
instruments for New York Mercantile Exchange (“NYMEX”) natural gas
swaps.
Level 2 –
Inputs other than quoted prices included within Level 1 that are either directly
or indirectly observable for the asset or liability, including (i) quoted prices
for similar assets or liabilities in active markets, (ii) quoted prices for
identical or similar assets or liabilities in inactive markets, (iii) inputs
other than quoted prices that are observable for the asset or liability and (iv)
inputs that are derived from observable market data by correlation or other
means.
Level 3 –
Unobservable inputs for the asset or liability, including situations where there
is little, if any, market activity for the asset or
liability. Included in Level 3 are the Partnership’s commodity based
and basis protection derivative instruments for Colorado Interstate Gas, or CIG,
based fixed-price natural gas swaps, collars and floors, oil swaps, and natural
gas basis protection swaps.
Derivative Financial
Instruments. The Partnership measures the fair value of its
derivatives based upon quoted market prices, where available. The
Managing General Partner’s valuation determination includes: (1) identification
of the inputs to the fair value methodology through the review of counterparty
statements and other supporting documentation, (2) determination of the validity
of the source of the inputs, (3) corroboration of the original source of inputs
through access to multiple quotes, if available, or other information and (4)
monitoring changes in valuation methods and assumptions. The methods
described above may produce a fair value calculation that may not be indicative
of future fair values. The Managing General Partner’s valuation
determination also gives consideration to the nonperformance risk on PDC’s own
business interests and liabilities, as well as the credit standing of derivative
instrument counterparties. The Managing General Partner primarily
uses two investment grade financial institutions as counterparties to its
derivative contracts who hold the majority of the Managing General Partner’s
derivative assets. The Managing General Partner has evaluated the
credit risk of the Partnership’s derivative assets from counterparties using
relevant credit market default rates, giving consideration to amounts
outstanding for each counterparty and the duration of each outstanding
derivative position. The Managing General Partner has determined
based on this evaluation, that the impact of counterparty non-performance on the
fair value of the Partnership’s derivative instruments is insignificant for the
Partnership. As of December 31, 2008, no valuation allowance by the
Partnership has been recorded. Furthermore, while the Managing
General Partner believes these valuation methods are appropriate and consistent
with that used by other market participants, the use of different methodologies,
or assumptions, to determine the fair value of certain financial instruments
could result in a different estimate of fair value. The Partnership
has estimated the net fair value of Partnership’s commodity based and basis
protection derivatives as of December 31, 2008 to be $1.2 million.
Non-Derivative Financial Assets and
Liabilities. The carrying values of the financial instruments
comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable
and accrued expenses” and “Due from (to) Managing General Partner-other, net”
approximate fair value due to the short-term maturities of these
instruments.
In
accordance with FAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Partnership assesses its proved oil
and gas properties for possible impairment, upon a triggering event, by
comparing net capitalized costs to estimated undiscounted future net cash flows
on a field-by-field basis using estimated production based upon prices at which
the Partnership reasonably estimates the commodity to be sold. The
estimates of future prices may differ from current market prices of oil and
natural gas. Certain events, including but not limited to, downward
revisions in estimates to the Partnership’s reserve quantities, expectations of
falling commodity prices or rising operating costs could result in a triggering
event and, therefore, a possible impairment of the Partnership’s oil and natural
gas properties. If net capitalized costs exceed undiscounted future
net cash flows, the measurement of impairment is based on estimated fair value
utilizing a future discounted cash flow analysis and is measured by the amount
by which the net capitalized costs exceed their fair value. During
the year ended December 31, 2008, no impairment of oil and gas properties was
recognized.
The
Partnership accounts for asset retirement obligations by recording the fair
value of its plugging and abandonment obligations when incurred, which is at the
time the well is completely drilled. Upon initial recognition of an
asset retirement obligation, the Partnership increases the carrying amount of
the long-lived asset by the same amount as the liability. Over time,
the asset retirement obligations are accreted, over the estimated lives of the
related assets, for the change in their present value. The initial
capitalized costs are depleted over the useful lives of the related assets,
through charges to DD&A expense. If the fair value of the
estimated asset retirement obligation changes, an adjustment is recorded to both
the asset retirement obligation and the asset retirement cost. Revisions in
estimated liabilities can result from revisions of estimated inflation rates,
escalating retirement costs and changes in the estimated timing of settling
asset retirement obligations. See Note 8, Asset Retirement Obligations
to the accompanying financial statements, for a reconciliation of asset
retirement obligation activity.
Recent Accounting
Standards
See Note
2, Summary of Significant
Accounting Policies to the accompanying financial statements included in
this report, for recently issued and implemented accounting standards including
the SEC published final rule, Modernization of Oil and Gas
Reporting. The most notable change of this final rule includes
the replacement of the single day period-ending pricing for valuing oil and
natural gas reserves with a 12-month average of the first day of the month price
for each month within the reporting period.
|
Item 7A.
|
Quantitative
and Qualitative Disclosure About Market
Risk
|
Market-Sensitive Instruments
and Risk Management
The
Partnership's primary market risk exposure is commodity price risk and related
credit exposure. Management of the Managing General Partner has
established risk management processes to monitor and manage this market
risk.
Commodity
Price Risk
See Part
II, Item 7, Management’s
Discussion and Analysis of Financial Condition and Results of
Operations−Critical Accounting Policies and Estimates, Fair Value of Financial
Instruments, for further discussion of the accounting for derivative
contracts.
The
Partnership is exposed to the effect of market fluctuations in the prices of oil
and natural gas as they relate to the Partnership’s oil and natural gas sales
and marketing activities. Price risk represents the potential risk of
loss from adverse changes in the market price of oil and natural gas
commodities. The Managing General Partner employs established policies and
procedures to manage the risks associated with these market fluctuations using
commodity derivatives. The Partnership's policy prohibits the use of
oil and natural gas derivative instruments for speculative
purposes.
Valuation
of a contract’s fair value is performed internally and, while the Managing
General Partner uses common industry practices to develop the Partnership’s
valuation techniques, changes in pricing methodologies or the underlying
assumptions could result in different fair values. While the Managing
General Partner believes these valuation methods are appropriate and consistent
with those used by other market participants, the use of different
methodologies, or assumptions, to determine the fair value of certain financial
instruments could result in a different estimate of fair value.
Derivative
Strategies
The
Partnership’s results of operations and operating cash flows are affected by
changes in market prices for oil and natural gas. To mitigate a
portion of the exposure to adverse market changes, the Managing General Partner
has entered into various derivative contracts. As of December 31,
2008, the Partnership’s oil and natural gas derivative instruments were
comprised of “swaps” and “collars” in addition to “basis protection
swaps.” These instruments generally consist of CIG-based contracts
for Colorado gas production and NYMEX-based contracts for Colorado oil
production. In addition to the swaps, collars and basis protection
swaps, derivative instruments which remain in effect at December 31, 2008, the
Managing General Partner previously utilized “floor” contracts to reduce the
impact of natural gas and oil price declines in subsequent
periods.
|
|
·
|
Collars
contain a fixed floor price (put) and ceiling price (call). If
the market falls below the fixed put strike price, PDC, as Managing
General Partner, receives the market price from the purchaser and receives
the difference between the put strike price and market price from the
counterparty. If the market price exceeds the fixed call strike
price, PDC, as Managing General Partner, receives the market price from
the purchaser and pays the difference between the call strike price and
market price to the counterparty. If the market price is
between the call and put strike price, no payments are due to or from the
counterparty.
|
|
|
·
|
Swaps
are arrangements that guarantee a fixed price. If the market
price is below the fixed contract price, PDC, as Managing General Partner,
receives the market price from the purchaser and receives the difference
between the market price and the fixed contract price from the
counterparty. If the market price is above the fixed contract price,
PDC, as Managing General Partner, receives the market price from the
purchaser and pays the difference between the market price and the fixed
contract price to the counterparty.
|
|
|
·
|
Basis
protection swaps are arrangements that guarantee a price differential for
natural gas from a specified delivery point. For CIG basis
protection swaps, which have negative differentials to NYMEX, PDC, as
Managing General Partner, receives a payment from the counterparty if the
price differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the stated
terms of the contract.
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|
|
·
|
Floors
contain a floor price (put) whereby PDC, as Managing General Partner,
receives the market price from the purchaser and the difference between
the market price and floor price from the counterparty if the commodity
market price falls below the floor strike price, but receives no payment
when the commodity market price exceeds the floor
price.
|
The
Managing General Partner enters into derivative instruments for Partnership
production to reduce the impact of price declines in future
periods. While these derivatives are structured to reduce the
Partnership’s exposure to changes in price associated with the derivative
commodity, they also limit the benefit the Partnership might otherwise have
received from price changes in the physical market. The Partnership
believes the derivative instruments in place continue to be effective in
achieving the risk management objectives for which they were
intended.
The
following table presents monthly average CIG and NYMEX closing prices for
natural gas and oil in 2008 and 2007, as well as average sales prices the
Partnership realized for the respective commodity.
|
Year
Ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Average
index closing price
|
||||||||
|
Natural
gas (per
MMbtu)
|
||||||||
|
CIG
|
$ | 6.22 | $ | 3.97 | ||||
|
Oil
(per
Barrel)
|
||||||||
|
NYMEX
|
104.42 | 69.79 | ||||||
|
Average
sales price
|
||||||||
|
Natural
gas (per
Mcf)
|
$ | 6.51 | $ | 4.89 | ||||
|
Oil
(per
Barrel)
|
89.15 | 58.04 | ||||||
As of
December 31, 2008, the fair value of the Partnership’s derivative instruments
was a net asset of $1.2 million compared to a net liability of approximately
$39,000 as of December 31, 2007. Based on a sensitivity analysis as
of June 30, 2009, it was estimated that a 10% increase in oil and gas prices,
inclusive of basis, over the entire period for which the Partnership has
derivatives currently in place would result in a decreased fair value of
approximately $5,000 and a 10% decrease in oil and gas prices would result in an
increase in fair value of $1.1 million.
See Item
7, Management’s Discussion and
Analysis of Financial Condition and Results of Operations, Results of
Operations−Oil and Gas Price Risk Management, Net for a detailed
discussion of the Partnership’s open derivative positions related to the
Partnership’s oil and gas sales activities and a summary of the Partnership’s
open derivative positions.
Credit
Risk
Credit
risk represents the loss that the Partnership would incur if a counterparty
fails to perform under its contractual obligations. When the fair
value of a derivative contract is positive, the counterparty owes the Managing
General Partner, which in turn owes the Partnership, thus creating repayment
risk from counterparties.
The
Managing General Partner attempts to reduce credit risk by diversifying its
counterparty exposure and entering into transactions with high-quality
counterparties. When exposed to credit risk, the Managing General
Partner analyzes the counterparties’ financial condition prior to entering into
an agreement, establishes credit limits and monitors the appropriateness of
those limits on an ongoing basis. PDC, the Managing General Partner
has had no counterparty default losses. The Managing General
Partner’s receivables are from a diverse group of companies, including major
energy companies, both upstream and mid-stream, financial institutions and
end-users in various industries. The Managing General Partner
monitors their creditworthiness through credit reports and rating agency
reports.
The
Managing General Partner has evaluated the credit risk of the Partnership’s
assets from counterparties using relevant credit market default rates, giving
consideration to amounts outstanding for each counterparty and the duration of
each outstanding derivative position. Based on the Managing General
Partner’s evaluation, the Partnership has determined that the impact of the
nonperformance of counterparties on the fair value of the Partnership’s
derivative instruments is insignificant. At December 31, 2008 and
2007 no valuation allowance has been recorded by the
Partnership. Furthermore, while the Managing General Partner believes
these valuation methods are appropriate and consistent with that used by other
market participants, the use of different methodologies or assumptions, to
determine fair value of certain financial instruments could result in a
different estimate of fair value.
Disclosure
of Limitations
As the
information above incorporates only those exposures which existed as of or prior
to June 30, 2009, it does not consider those exposures or positions which could
arise after that date. As a result, the Partnership's ultimate
realized gain or loss with respect to commodity price fluctuations depends on
the future exposures that arise during the period, the Partnership's hedging
strategies at the time and commodity prices at the time.
|
Item 8.
|
Financial
Statements and Supplementary Data
|
The
financial statements are attached to this Form 10-K beginning at page
F-1.
Supplemental
financial information required by this Item can be found in Item 7, Management’s Discussion and Analysis of Financial
Condition and Results of Operations of this report.
|
Item 9.
|
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
|
None
|
Item 9A(T).
|
Controls
and Procedures
|
The
Partnership has no direct management or officers. The management,
officers and other employees that provide services on behalf of the Partnership
are employed by the Managing General Partner.
(a) Evaluation of Disclosure
Controls and Procedures
As of
December 31, 2008, PDC, as Managing General Partner on behalf of the
Partnership, carried out an evaluation, under the supervision and with the
participation of the Managing General Partner's management, including its Chief
Executive Officer and Chief Financial Officer, of the effectiveness of the
design and operation of the Partnership's disclosure controls and
procedures. Disclosure controls and procedures are defined in
Exchange Act Rules 13a-15(e) and 15d-15(e) as the controls and procedures of an
issuer that are designed to ensure that information required to be disclosed by
the issuer in the reports it files or submits under the Exchange Act is
recorded, processed, summarized and reported, within the time periods specified
in the SEC’s rules and forms, and that such information is accumulated and
communicated to the issuer’s management, including its principal executive and
principal financial officers, or persons performing similar functions, as
appropriate to allow timely decisions regarding required
disclosure. Based upon that evaluation, the Managing General
Partner’s Chief Executive Officer and Chief Financial Officer concluded that the
Partnership’s disclosure controls and procedures were not effective as of
December 31, 2008 due to the existence of the material weakness described below
in Management’s Report on
Internal Control Over Financial Reporting included in this Item
9A(T).
(b) Management’s Report on
Internal Control Over Financial Reporting
Management
of PDC, the Managing General Partner of the Partnership, is responsible for
establishing and maintaining adequate internal control over financial
reporting. Internal control over financial reporting is defined in
Exchange Act Rules 13a-15(f) and 15d-15(f) as a process designed by, or under
the supervision of, the issuer’s principal executive and principal financial
officers, or persons performing similar functions, and effected by the issuer’s
board of directors, management and other personnel, to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with accounting
principles generally accepted in the United States of America and includes those
policies and procedures that:
Pertain
to the maintenance of records that in reasonable detail accurately and fairly
reflect the transactions and dispositions of the assets of the
issuer;
|
|
·
|
Provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with accounting
principles generally accepted in the United States of America and that
receipts and expenditures of the issuer are being made only in accordance
with authorizations of management and directors of the issuer;
and
|
|
|
·
|
Provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of the issuer’s assets that
could have a material effect on the financial statements of the
issuer.
|
|
|
·
|
Because
of its inherent limitations, internal control over financial reporting may
not prevent or detect 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 policies or procedures may
deteriorate.
|
Management
of the Managing General Partner has assessed the effectiveness of the
Partnership’s internal control over financial reporting as of December 31, 2008,
based upon the criteria established in “Internal Control - Integrated Framework”
issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this evaluation, management of the Managing
General Partner concluded that the Partnership did not maintain effective
internal control over financial reporting as of December 31, 2008 due to the
material weakness discussed below. A material weakness is a
deficiency, or a combination of deficiencies, in internal control over financial
reporting, such that there is a reasonable possibility that a material
misstatement of the registrant’s annual or interim financial statements will not
be prevented or detected on a timely basis. Management of PDC, the
Managing General Partner, identified the following material weakness related to
the effectiveness of the Partnership’s internal control over financial reporting
as of December 31, 2008:
|
|
·
|
For
the transactions that are directly related to and processed by the
Partnership, the Partnership failed to maintain sufficient documentation
to adequately assess the operating effectiveness of internal control over
financial reporting. More specifically, the Partnership’s
financial close and reporting narrative failed to adequately describe the
process, identify key controls and assess segregation of
duties. This material weakness has not been
remediated.
|
This
Annual Report does not include an attestation report of the Partnership’s
independent registered public accounting firm regarding internal control over
financial reporting which is not required to be included until the 2010 Annual
Report is filed, pursuant to the final implementation extension of Item 308T
(a)(4) of Regulation S-K, granted by the SEC on October 2, 2009.
(c) Remediation of Material
Weaknesses in Internal Control
Management
of the Managing General Partner identified the following material weaknesses
related to the effectiveness of the Partnership’s internal controls over
financial reporting as of December 31, 2007:
|
|
·
|
The
support for the Partnership’s general ledger depends in part on the
effectiveness of controls of the Managing General Partner’s
spreadsheets. The overall ineffectiveness of the Managing
General Partner's spreadsheet controls could have a material effect on the
Partnership’s financial statements. The Partnership did not
maintain effective controls to ensure the completeness, accuracy, and
validity of key financial statement spreadsheets generated by the Managing
General Partner. These spreadsheets are utilized by the
Partnership to support significant balance sheet and income statement
accounts.
|
|
|
·
|
The
support for the Partnership’s derivative calculations depends in part on
the effectiveness of controls of the Managing General Partner’s
process. The overall effectiveness of the Managing General
Partner's derivative controls could have a material effect on the
Partnership’s financial statements. The Partnership did not
maintain effective controls to ensure that the Managing General Partner
had policies and procedures, or personnel with sufficient technical
expertise to record derivative activities in accordance with generally
accepted accounting principles.
|
The
Partnership made no changes in its internal control over financial reporting
(such as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act
of 1934) during the quarter ended December 31, 2008. During the first
and third quarters of 2008, the Managing General Partner made the following
changes in the Partnership's internal control over financial reporting that has
materially affected, or is reasonably likely to materially affect, the
Partnership's internal controls over financial reporting:
During
the first quarter of 2008, the Managing General Partner implemented the general
ledger, accounts receivable, cash receipts, revenue, financial reporting, and
joint interest billing modules as part of a new broader financial
system. The Managing General Partner had planned to implement a
Partnership distribution module in 2008, however, the Managing General Partner
currently expects this module to be in place during 2009. The new
financial system enhanced operating efficiencies and provided more effective
management of Partnership business operations and processes. The
Managing General Partner believes the phased-in implementation approach it is
taking reduces the risks associated with the new financial system
implementation. The Managing General Partner has taken the necessary steps to
monitor and maintain appropriate internal controls during this period of
change. These steps include documenting all new business process
changes related to the new financial system; testing all new business processes
on the new financial system; and conducting training related to the new business
processes and to the new financial system software. The Managing
General Partner expects the implementation of the new financial system will
strengthen the overall systems of internal controls due to enhanced automation
and integration of related processes. The Managing General Partner
continues to modify the design and documentation of internal control processes
and procedures related to the new financial system to supplement and complement
existing internal controls over financial reporting. The system
changes were developed to integrate systems and consolidate information, and
were not undertaken in response to any actual or perceived deficiencies in the
Partnership's internal control over financial reporting. Testing of
the controls related to these new systems was included in the scope of the
Managing General Partner's assessment of the Partnership's internal control over
financial reporting for 2008.
During
the third quarter of 2008, the Managing General Partner improved controls over
certain key financial statement spreadsheets that support all significant
balance sheet and income statement accounts. Specifically, the
Managing General Partner enhanced the spreadsheet policy to provide additional
clarification and guidance with regard to risk assessment and enforced controls
over: 1) the security and integrity of the data used in the various
spreadsheets, 2) access to the spreadsheets, 3) changes to spreadsheet
functionality and the related approval process and documentation and 4)
increased management’s review of the spreadsheets.
During
the third quarter of 2008, in addition to accredited derivative training
attended by key personnel, the Managing General Partner created and documented a
desktop procedure to: 1) ensure the completeness and accuracy of the
Managing General Partner’s derivative activities and 2) supplement key controls
previously existing in the process. Further, the desktop procedure
provides for a more robust review of the Managing General Partner’s derivative
process. This procedure continued to be enhanced throughout the
fourth quarter of 2008.
Based on
the changes in the Managing General Partner’s internal control over financial
reporting discussed above, the Managing General Partner has concluded that the
first two material weaknesses which were identified as of December 31, 2007 had
been remediated as of December 31, 2008.
|
Item 9B.
|
Other
Information
|
None
PART III
|
Item
10.
|
Directors,
Executive Officers and Corporate
Governance
|
The
Partnership has no directors or executive officers. The Partnership
is managed by PDC, the Managing General Partner.
PDC, a
publicly-owned Nevada corporation, was organized in 1955. The common
stock of PDC is traded on the NASDAQ Global Select Market under the symbol
"PETD." Since 1969, PDC has been engaged in the business of exploring
for, developing and producing oil and gas primarily in West Virginia, Tennessee,
Pennsylvania, Ohio, Michigan and the Rocky Mountains. As of December
31, 2008, PDC had approximately 317 employees. PDC will make
available to Investor Partners, upon request, audited financial statements of
PDC for the most recent fiscal year and unaudited financial statements for
interim periods. PDC's Internet address is
www.petd.com. PDC posts on its Internet Web site its periodic and
current reports and other information, including its audited financial
statements, that it files with the SEC, as well as various charters and other
corporate governance information.
As the
Managing General Partner, PDC actively manages and conducts the business of the
Partnership. PDC has the full authority under the D&O Agreement
to conduct the Partnership's business. PDC is responsible for
maintaining Partnership bank accounts, collecting Partnership revenues, making
distributions to the partners, delivering reports to the partners, and
supervising the drilling, completion, and operation of the Partnership's natural
gas and oil wells. The executive officers of PDC are full-time
employees of PDC. As such, these individuals devote the entirety of
their daily time to the business and operations of PDC. An element of
these individuals’ job responsibilities requires that they devote such time and
attention to the business and affairs of the Partnership as is reasonably
required. This time commitment varies for each individual and may
vary over the life of the Partnership.
In
addition to managing the affairs of the Partnership, the management and
technical staff of PDC also manage the corporate affairs of PDC, the affairs of
32 other limited partnerships and other joint ventures formed over the
years. PDC owns an interest in all of the 32 limited partnerships for
which it acts as Managing General Partner. Because PDC must divide
its attention and efforts among many unrelated parties, the Partnership does not
receive PDC’s full attention or efforts at all times, however, PDC believes that
it devotes sufficient time, attention and expertise to the Partnership to
appropriately manage the affairs of the Partnership.
Although
the Partnership has no Code of Ethics, PDC has a Code of Ethics that applies to
its senior executive officers. The Code of Ethics is posted on PDC’s
website at www.petd.com.
Experience and Capabilities
as Driller/Operator
PDC is
contracted to serve as operator for the Partnership wells. Since
1969, PDC has drilled wells in Colorado, West Virginia, Tennessee, Michigan,
North Dakota, Kansas, Wyoming, Texas and Pennsylvania. PDC currently
operates approximately 4,712 wells.
PDC
employs geologists who develop opportunities for drilling by PDC and who help
oversee the drilling process. In addition, PDC has an engineering
staff that is responsible for well completions and recompletions, pipelines, and
production operations. PDC retains drilling subcontractors,
completion subcontractors, and a variety of other subcontractors in the
performance of the work of drilling contract wells. In addition to
technical management, PDC may provide services, at competitive rates, from
PDC-owned service rigs, a water truck, steel tanks used temporarily on the well
location during the drilling and completion of a well, roustabouts, and other
assorted small equipment and services. A roustabout is an oil and
natural gas field employee who provides skilled general labor for assembling
well components and other similar tasks. PDC may lay short gathering
lines, or may subcontract all or part of the work where it is more cost
effective for the Partnership. PDC employs full-time well tenders and
supervisors to operate its wells. In addition, the engineering staff
evaluates oil and natural gas reserves of all wells at least annually and
reviews individual well performance against expectations. All
services provided by PDC are provided at rates less than or equal to prevailing
rates for similar services provided by unaffiliated persons in the
area.
Petroleum Development
Corporation
The
executive officers and directors of PDC, their principal occupations for the
past five years and additional information is set forth below:
|
Name
|
Age
|
Positions
and
Offices Held
|
Director
Since
|
Directorship
Term Expires
|
||||
|
Richard
W. McCullough
|
57
|
Chairman
and Chief Executive Officer
|
2007
|
2010
|
||||
|
Gysle
R. Shellum
|
57
|
Chief
Financial Officer
|
-
|
-
|
||||
|
R.
Scott Meyers
|
35
|
Chief
Accounting Officer
|
-
|
-
|
||||
|
Daniel
W. Amidon
|
49
|
General
Counsel and Secretary
|
-
|
-
|
||||
|
Barton
R. Brookman, Jr.
|
47
|
Senior
Vice President Exploration and Production
|
-
|
-
|
||||
|
Lance
Lauck
|
46
|
Senior
Vice President Business Development
|
-
|
-
|
||||
|
Vincent
F. D'Annunzio
|
57
|
Director
|
1989
|
2010
|
||||
|
Jeffrey
C. Swoveland
|
54
|
Director
|
1991
|
2011
|
||||
|
Kimberly
Luff Wakim
|
51
|
Director
|
2003
|
2012
|
||||
|
David
C. Parke
|
42
|
Director
|
2003
|
2011
|
||||
|
Anthony
J. Crisafio
|
56
|
Director
|
2006
|
2012
|
||||
|
Joseph
E. Casabona
|
66
|
Director
|
2007
|
2011
|
||||
|
Larry
F. Mazza
|
49
|
Director
|
2007
|
2010
|
||||
|
James
M. Trimble
|
61
|
Director
|
2009
|
2010
|
Richard
W. McCullough was appointed Chief
Executive Officer in June 2008 and Chairman in November
2008. Mr. McCullough also served PDC as President since March
2008. Mr. McCullough served as Chief Financial Officer from
November 2006 until November 2008. Prior to joining PDC,
Mr. McCullough served as an energy consultant from July 2005 to November
2006. From January 2004 to July 2005, Mr. McCullough served as
President and Chief Executive Officer of Gasource, LLC, Dallas, Texas, a
marketer of long-term, natural gas supplies. From 2001 to 2003,
Mr. McCullough served as an investment banker with J.P. Morgan
Securities, Atlanta, Georgia, and served in the public finance utility group
supporting bankers nationally in all natural gas
matters. Additionally, Mr. McCullough has held senior positions
with Progress Energy, Deloitte and Touche, and the Municipal Gas Authority of
Georgia. Mr. McCullough, a CPA, was a practicing certified
public accountant for 8 years. Mr. McCullough serves as Chairman
of the Executive Committee and serves on the Planning and Finance
Committee.
Gysle R.
Shellum was
appointed Chief Financial Officer effective November 11,
2008. Prior to joining PDC, Mr. Shellum served as Vice
President, Finance and Special Projects of Crosstex Energy, L.P., Dallas,
Texas. Mr. Shellum served in this capacity from September 2004
through September 2008. Prior thereto from March 2001 until September
2004, Mr. Shellum served as a consultant to Value Capital, a private
consulting firm in Dallas, where he worked on various projects, including
corporate finance and Sarbanes-Oxley Act compliance. Crosstex Energy, L.P. is a
publicly traded Delaware limited partnership, whose securities are listed on the
NASDAQ Global Select Market and is an independent midstream energy company
engaged in the gathering, transmission, treating, processing and marketing of
natural gas and natural gas liquids.
R. Scott
Meyers was
appointed Chief Accounting Officer on April 2, 2009. Prior to
joining PDC, Mr. Meyers served as a Senior Manager with Schneider Downs
Co., Inc., an accounting firm based in Pittsburgh,
Pennsylvania. Mr. Meyers served in such capacity from April 2008
to March 2009. Prior thereto, from November 2002 to March 2008,
Mr. Meyers was employed by PricewaterhouseCoopers LLP, the last two and
one-half years serving as Senior Manager.
Daniel
W. Amidon was appointed General
Counsel and Secretary in July 2007. Prior to his current position,
Mr. Amidon was employed by Wheeling-Pittsburgh Steel Corporation beginning
in July 2004; he served in several positions including General Counsel and
Secretary. Prior to his employment with Wheeling-Pittsburgh Steel,
Mr. Amidon worked for J&L Specialty Steel Inc. from 1992 through July
2004 in positions of increasing responsibility, including General Counsel and
Secretary. Mr. Amidon practiced with the Pittsburgh law firm of
Buchanan Ingersoll PC from 1986 through 1992.
Barton
R. Brookman, Jr. was appointed Senior Vice President Exploration and
Production in March 2008. Previously Mr. Brookman served as Vice
President Exploration and Production since joining PDC in July
2005. Prior to joining PDC, Mr. Brookman worked for Patina Oil
and Gas and its predecessor Snyder Oil for 17 years in a series of
positions of increasing responsibility, ending his service as Vice President of
Operations of Patina.
Lance
Lauck was
appointed Senior Vice President Business Development on August 31,
2009. Prior to joining PDC, Mr. Lauck served as Vice President
Acquisitions and Business Development with Quantum Resources Management, LLC
based in Denver Colorado. Beginning in June 2006, Mr. Lauck was
responsible for valuation and acquisition of oil and gas exploration and
production properties. Prior to his employment at Quantum Resources,
Mr. Lauck was employed by Anadarko Petroleum Corporation from 1988 to 2006 in
The Woodlands, Texas. Mr. Lauck served Anadarko in various capacities
beginning as a Senior Production Engineer and exited as General Manager,
Corporate Development.
Vincent
F. D’Annunzio has served as president of Beverage Distributors, Inc.
located in Clarksburg, West Virginia since 1985. Mr. D’Annunzio
serves as Chairman of the Nominating and Governance Committee and serves on the
Executive Committee and the Compensation Committee.
Jeffrey
C. Swoveland has served as Chief Operating Officer of ReGear, Inc.
(previously named Coventina Healthcare Enterprises), a medical device company
that develops and markets products which reduce pain and increase the rate of
healing through therapeutic, deep tissue heating, since May
2007. Previously, Mr. Swoveland served as Chief Financial
Officer of Body Media, Inc., a life-science company specializing in the design
and development of wearable body monitoring products and services, from
September 2000 to May 2007. Prior thereto, Mr. Swoveland held
various positions, including Vice-President of Finance, Treasurer and interim
Chief Financial Officer with Equitable Resources, Inc., a diversified natural
gas company, from 1994 to September 2000. Mr. Swoveland serves as a member
of the Board of Directors of Linn Energy, LLC, a public, independent natural gas
and oil company. Mr. Swoveland serves as Presiding Independent
Director, and serves on the Audit Committee, the Planning and Finance Committee
and Executive Committee.
Kimberly
Luff Wakim, an Attorney and a Certified Public Accountant, is a Partner
with the Pittsburgh, Pennsylvania law firm, Thorp, Reed & Armstrong
LLP, where she serves as a member of the Executive Committee. Ms. Wakim has
practiced law with Thorp, Reed & Armstrong LLP since
1990. Ms. Wakim serves as Chairman of the Compensation Committee and
serves on the Audit Committee and the Nominating and Governance
Committee.
David C.
Parke is a Managing Director in the investment banking group of
Boenning & Scattergood, Inc., West Conshohocken, Pennsylvania, a
full-service investment banking firm. Prior to joining
Boenning & Scattergood in November 2006, he was a Director with Mufson
Howe Hunter & Company LLC, Philadelphia, Pennsylvania, an investment
banking firm, from October 2003 to November 2006. From 1992 through
2003, Mr. Parke was Director of Corporate Finance of Investec, Inc. and its
predecessor Pennsylvania Merchant Group Ltd., investment banking
companies. Prior to joining Pennsylvania Merchant Group,
Mr. Parke served in the corporate finance departments of Wheat First
Butcher & Singer, now part of Wachovia Securities, and Legg Mason,
Inc., now part of Stifel Nicolaus. Mr. Parke serves on the Planning
and Finance Committee, the Compensation Committee and on the Nominating and
Governance Committee.
Anthony
J. Crisafio, a Certified Public Accountant, serves as an independent
business consultant providing financial and operational advice to businesses and
has done so since 1995. Additionally, Mr. Crisafio has served as
the Chief Operating Officer of Cinema World, Inc. from 1989 until 1993 and was a
partner with Ernst & Young from 1986 until 1989. Mr.
Crisafio serves as the Chairman of the Audit Committee and serves on the
Compensation Committee.
Joseph
E. Casabona served as Executive Vice President and member of the Board of
Directors of Denver- based Energy Corporation of America, a natural gas
exploration and development company, from 1985 to his retirement in May
2007. Mr. Casabona’s responsibilities included strategic
planning as well as executive oversight of the drilling operations in the
continental United States and internationally. In 2008
Mr. Casabona assumed the title of Chief Executive Officer of Paramax
Resources Ltd, a junior public Canadian oil & gas company (PMXRF)
engaged in the business of acquiring and exploration of oil and gas prospects,
primarily in Canada and Idaho. Mr. Casabona serves as Chairman of the
Planning and Finance Committee and serves on the Audit Committee.
Larry F.
Mazza is President and Chief Executive Officer of MVB Financial
Corporation in Fairmont, West Virginia. He has been Chief Executive
Officer since March 2005, and added the duties of President in January of
2009. Prior to such position, Mr. Mazza served as Senior Vice
President Retail Banking Manager & President & CEO for
BB&T and its predecessors in West Virginia, where he was employed from
June 1986 to March 2005. Mr. Mazza serves on the Nominating and
Governance Committee and the Compensation Committee.
James M.
Trimble serves as Managing Director and Chief Executive Officer of the
parent and US subsidiaries of Grand Gulf Energy Limited, a public company traded
on the Australian Exchange. In January 2005, Mr. Trimble founded
Grand Gulf Energy Company LLC, an Exploration and Development company focused
primarily on drilling in mature basins in Texas, Louisiana, and
Oklahoma. Prior to founding Grand Gulf Energy, Mr. Trimble served as
President, Chief Executive Officer and Chairman of the Board of TexCal Energy
LLC from June 2002 through December 2004. From July 2000 to December
2001, Mr. Trimble was President and a member of the Board of Directors of
Elysium Energy L.L.C., an exploration and production company. From
1983 to 2000, he served as Senior Vice President – Exploration and Production of
Cabot Oil and Gas Company, a publicly held, mid-sized exploration and production
company. Mr. Trimble serves on the Planning and Finance
Committee.
The Audit
Committee of the Board of Directors is comprised of Directors Swoveland,
Crisafio, Wakim and Casabona. The Board has determined that the Audit
Committee is comprised entirely of independent directors as defined by the
NASDAQ rule 4200(a) (15). Anthony J. Crisafio chairs the Audit
Committee. All audit committee members qualify as audit committee
financial experts and are independent of management.
|
Item 11.
|
Executive
Compensation
|
The
Partnership does not have any employees or executives of its
own. None of PDC's officers or directors receive any direct
remuneration, compensation or reimbursement from the
Partnership. These persons receive compensation solely from
PDC. The management fee and other amounts paid to the Managing
General Partner by the Partnership are not used to directly compensate or
reimburse PDC’s officers or directors. No management fee was paid to
PDC in 2008 or 2007 as the Partnership is not required to pay a management fee
other than a one time fee paid in the initial year of formation per the
Agreement. The Partnership pays a monthly fee for each producing well
based upon competitive industry rates for operations and field supervision and
$75 per well per month for Partnership related general and administrative
expenses that include accounting, engineering and management of the Partnership
by the Managing General Partner. See Item 13, Certain Relationships and Related
Transactions, and Director Independence for a discussion of compensation
paid by the Partnership to the Managing General Partner.
Compensation Committee
Interlocks and Insider Participation
There are
no Compensation Committee interlocks.
|
Item 12.
|
Security
Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters
|
As of
September 30, 2009 the Partnership had 899.94 units of limited partnership
interest and no units of additional general partnership interest
outstanding. No director or officer of PDC owns any
units. Subject to certain conditions, individual investor partners
may present their units to PDC for purchase. Pursuant to the
Partnership Agreement, PDC is not obligated to purchase more than 10% of the
total outstanding units in any calendar year if such units are presented to PDC
for repurchase. As of June 30, 2009, PDC has purchased 17.02
Partnership units from Investor Partners. PDC owns a 20% Managing
General Partner partnership interest in the Partnership.
|
Item 13.
|
Certain
Relationships and Related Transactions, and Director
Independence
|
Compensation to the Managing
General Partner and Affiliates
The
Managing General Partner transacts all of the Partnership’s business on behalf
of the Partnership. See Note 3, Transactions with Managing General
Partner and Affiliates to the accompanying financial statements, for
information regarding compensation to and transactions with the Managing General
Partner and affiliates.
Related Party Transaction
Policies and Approval
The
Limited Partnership Agreement and the Drilling and Operating Agreement with
Petroleum Development Corporation govern related party transactions, including
those described above. The Partnership does not have any written policies
or procedures for the review, approval or ratification of transactions with
related persons outside the agreements.
Other Agreements and
Arrangements
Executive
officers of the Managing General Partner are eligible to invest in a
Board-approved executive drilling program, as approved by the Board of
Directors.
These
executive officers may profit from their participation in the executive drilling
program because they invest in wells at cost and do not have to pay drilling
compensation, management fees or broker commissions and therefore obtain an
interest in the wells at a reduced price than that which is generally charged to
the investing partners in a Partnership. Investor partners
participating in drilling through a partnership are generally charged a profit
or markup above the cost of the wells, management fees and commissions at rates
which are generally similar to those for this Partnership outlined in Note 3,
Transactions with Managing
General Partner and Affiliates to the accompanying financial
statements.
Through
the executive drilling program, certain former executive officers invested in
the wells developed by PDC in which the Partnership invested. The
executive program allowed PDC to sell working interests to PDC executive
officers in the wells that PDC will develop for the
Partnership. Participating officers thereby own parallel undivided
working interests in all of the wells that the Partnership has invested
in. Prior to the funding of the Partnership, each executive officer
who chose to participate in the executive program advised PDC of the dollar
amount of his investment participation, and thereby acquired a working interest
in the wells in which the Partnership acquired a working interest, the acquired
working interest being parallel to the working interest of the Partnership and
the investor partners. The officers’ percentage in each well is
proportionate to the Partnership’s working interest among all of the
Partnership’s wells based upon the officers’ investment amount. PDC
may also sell working interests in these wells, also prior to the funding of the
Partnership, to other parties unaffiliated with PDC. The aggregate
ownership percentage of these former executive officers ranges from .1269% to
.145% of each well in the Partnership. The Board believes that having
the executive officers invest in wells with PDC and other investor partners
helps to create a commonality of interests much like share ownership creates a
commonality of interests between the shareholders and executive
officers.
Director
Independence
The
Partnership has no directors. The Partnership is managed by the
Managing General Partner. See Item 10, Directors, Executive Officers and
Corporate Governance.
|
Item 14.
|
Principal
Accountant Fees and Services
|
There
were audit billings from the Partnership’s independent registered public
accounting firm, PricewaterhouseCoopers LLP (“PwC”), of approximately $145,000
and $82,000 for the audits for the years ended December 31, 2008 and
2007, respectively. For the years ended December 31, 2008
and 2007, there were tax billings from the Partnership’s independent registered
public accounting firm, PwC, of approximately $7,000 and $8,000,
respectively.
Audit
Committee Pre-Approval Policies and Procedures
The
Sarbanes-Oxley Act of 2002 requires that all services provided to the
Partnership by its independent registered public accounting firm be subject to
pre-approval by the Audit Committee or authorized members of the
Committee. The Partnership has no Audit Committee. The
Audit Committee of PDC, as Managing General Partner, has adopted policies and
procedures for pre-approval of all audit services and non-audit services to be
provided by the Partnership's independent registered public accounting
firm. Services necessary to conduct the annual audit must be
pre-approved by the Audit Committee annually at a meeting. Permissible non-audit
services to be performed by the independent registered public accounting firm
may also be approved on an annual basis by the Audit Committee if they are of a
recurring nature. Permissible non-audit services to be conducted by
the independent registered public accounting firm, which are not eligible for
annual pre-approval, must be pre-approved individually by the full Audit
Committee or by an authorized Audit Committee member. Actual fees
incurred for all services performed by the independent registered public
accounting firm will be reported to the Audit Committee after the services are
fully performed. The duties of the Committee are described in the
Audit Committee Charter, which is available at the Managing General Partner,
PDC’s, website under Corporate
Governance.
|
Item 15.
|
Exhibits,
Financial Statement Schedules
|
|
(a)
|
The
index to Financial Statements is located on page
F-1.
|
|
(b)
|
Exhibits
index.
|
|
Incorporated by Reference
|
||||||||||||
|
Exhibit Number
|
Exhibit Description
|
Form
|
SEC File Number
|
Exhibit
|
Filing Date
|
Filed Herewith
|
||||||
|
3.1
|
Limited
Partnership Agreement
|
10-K
|
000-51219
|
3.1
|
08/05/2009
|
|||||||
|
3.2
|
Certificate
of limited partnership which reflects the organization of the Partnership
under West Virginia law
|
10-K
|
000-51219
|
3.2
|
08/05/2009
|
|||||||
|
10.1
|
Drilling
and operating agreement between PDC as Managing General Partner of the
Partnership
|
10-K
|
000-51219
|
10.1
|
08/05/2009
|
|||||||
|
10.3
|
Audited
Consolidated Financial Statements for the year ended December 31, 2008 of
Petroleum Development Corporation and its subsidiaries, as Managing
General Partner of the Partnership
|
10-K
|
000-07246
|
02/27/2009
|
||||||||
|
Incorporated by Reference
|
||||||||||||
|
Exhibit Number
|
Exhibit Description
|
Form
|
SEC File Number
|
Exhibit
|
Filing Date
|
Filed Herewith
|
||||||
|
Consent
of Ryder Scott Company, L.P., Petroleum Consultants
|
X
|
|||||||||||
|
Rule
13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum
Development Corporation, the Managing General Partner of the
Partnership.
|
X
|
|||||||||||
|
Rule
13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum
Development Corporation, the Managing General Partner of the
Partnership.
|
X
|
|||||||||||
|
Title
18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)
Certifications by Chief Executive Officer and Chief Financial Officer of
Petroleum Development Corporation, the Managing General Partner of the
Partnership.
|
X
|
|||||||||||
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.
PDC
2004-B Limited Partnership
By its
Managing General Partner
Petroleum
Development Corporation
By /s/ Richard W.
McCullough
Richard
W. McCullough
Chairman
and Chief Executive Officer
October
23, 2009
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
|
Title
|
Date
|
||
|
/s/
Richard W. McCullough
|
Chairman
and Chief Executive Officer
|
October
23, 2009
|
||
|
Richard
W. McCullough
|
Petroleum
Development Corporation
|
|||
|
Managing
General Partner of the Registrant
|
||||
|
(Principal
executive officer)
|
||||
|
/s/
Gysle R. Shellum
|
Chief
Financial Officer
|
October
23, 2009
|
||
|
Gysle
R. Shellum
|
Petroleum
Development Corporation
|
|||
|
Managing
General Partner of the Registrant
|
||||
|
(Principal
financial officer)
|
||||
|
/s/
R. Scott Meyers
|
Chief
Accounting Officer
|
October
23, 2009
|
||
|
R.
Scott Meyers
|
Petroleum
Development Corporation
|
|||
|
Managing
General Partner of the Registrant
|
||||
|
(Principal
accounting officer)
|
||||
|
/s/
Kimberly Luff Wakim
|
Director
|
October
23, 2009
|
||
|
Kimberly
Luff Wakim
|
Petroleum
Development Corporation
|
|||
|
Managing
General Partner of the Registrant
|
||||
|
/s/
Anthony J. Crisafio
|
Director
|
October
23, 2009
|
||
|
Anthony
J. Crisafio
|
Petroleum
Development Corporation
|
|||
|
Managing
General Partner of the Registrant
|
||||
|
/s/
Jeffrey C. Swoveland
|
Director
|
October
23, 2009
|
||
|
Jeffrey
C. Swoveland
|
Petroleum
Development Corporation
|
|||
|
Managing
General Partner of the Registrant
|
||||
|
/s/
Joseph E. Casabona
|
Director
|
October
23, 2009
|
||
|
Joseph
E. Casabona
|
Petroleum
Development Corporation
|
|||
|
Managing
General Partner of the Registrant
|
PDC 2004-B LIMITED PARTNERSHIP
Index to Financial
Statements
|
Report
of Independent Registered Public Accounting Firm
|
F-2
|
|
Balance
Sheets - December 31, 2008 and 2007
|
F-3
|
|
Statements
of Operations - For the Years Ended December 31, 2008 and
2007
|
F-4
|
|
Statements
of Partners' Equity - For the Years Ended December 31, 2008 and
2007
|
F-5
|
|
Statements
of Cash Flows - For the Years Ended December 31, 2008 and
2007
|
F-6
|
|
Notes
to Financial Statements
|
F-7
|
|
Supplemental
Oil and Gas Information - Unaudited
|
F-26
|
|
Unaudited
Condensed Quarterly Financial Statements:
|
|
|
Balance
Sheets - 2008
|
F-30
|
|
Balance
Sheets - 2007
|
F-31
|
|
Statements
of Operations - 2008
|
F-32
|
|
Statements
of Operations - 2007
|
F-33
|
|
Statements
of Cash Flows - 2008
|
F-34
|
|
Statements
of Cash Flows - 2007
|
F-35
|
|
Notes
to Unaudited Condensed Quarterly Financial Statements
|
F-36
|
 |
|
|
PricewaterhouseCoopers
LLP
600
Grant Street
Pittsburgh
PA 15219
Telephone
(412) 355 6000
Facsimile
(412) 355 8089
|
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Partners of the PDC 2004-B Limited Partnership,
In our
opinion, the accompanying balance sheets and the related statements of
operations, partners' equity and cash flows present fairly, in all material
respects, the financial position of PDC 2004-B Limited Partnership (the
"Partnership") at December 31, 2008 and 2007, and the results of its operations
and its cash flows for each of the two years in the period ended December 31,
2008 in conformity with accounting principles generally accepted in the United
States of America. These financial statements are the responsibility
of the Partnership's management. Our responsibility is to express an
opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for our opinion.
As
discussed in Note 3 to the financial statements, the Partnership has significant
related party transactions with Petroleum Development Corporation and its
subsidiaries.
/s/ PricewaterhouseCoopers
LLP
Pittsburgh,
Pennsylvania
October
22, 2009
PDC
2004-B LIMITED PARTNERSHIP
Balance
Sheets
As of
December 31, 2008 and 2007
|
Assets
|
2008
|
2007
|
||||||
|
Current
assets:
|
||||||||
|
Cash
and cash equivalents
|
$ | 91,612 | $ | 43,507 | ||||
|
Accounts
receivable
|
147,587 | 365,136 | ||||||
|
Oil
inventory
|
21,608 | - | ||||||
|
Due
from Managing General Partner-derivatives
|
995,593 | 30,002 | ||||||
|
Due
from Managing General Partner-other, net
|
964,412 | 821,800 | ||||||
|
Total
current assets
|
2,220,812 | 1,260,445 | ||||||
|
Oil
and gas properties, successful efforts method, at cost
|
20,106,098 | 20,135,900 | ||||||
|
Less: Accumulated
depreciation, depletion and amortization
|
(8,156,676 | ) | (6,758,975 | ) | ||||
|
Oil
and gas properties, net
|
11,949,422 | 13,376,925 | ||||||
|
Due
from Managing General Partner-derivatives
|
319,803 | - | ||||||
|
Due
from Managing General Partner-other, net
|
- | 83,133 | ||||||
|
Other
assets
|
7,464 | - | ||||||
|
Total
noncurrent assets
|
12,276,689 | 13,460,058 | ||||||
|
Total
Assets
|
$ | 14,497,501 | $ | 14,720,503 | ||||
|
Liabilities and Partners'
Equity
|
||||||||
|
Current
liabilities:
|
||||||||
|
Accounts
payable and accrued expenses
|
$ | 30,331 | $ | 36,555 | ||||
|
Due
to Managing General Partner-derivatives
|
- | 68,645 | ||||||
|
Total
current liabilities
|
30,331 | 105,200 | ||||||
|
Due
to Managing General Partner-derivatives
|
100,327 | - | ||||||
|
Asset
retirement obligations
|
161,487 | 152,707 | ||||||
|
Total
liabilities
|
292,145 | 257,907 | ||||||
|
Partners'
equity:
|
||||||||
|
Managing
General Partner
|
2,844,942 | 2,896,389 | ||||||
|
Limited
Partners - 899.94 units issued and outstanding
|
11,360,414 | 11,566,207 | ||||||
|
Total
Partners' equity
|
14,205,356 | 14,462,596 | ||||||
|
Total
Liabilities and Partners' Equity
|
$ | 14,497,501 | $ | 14,720,503 | ||||
See
accompanying notes to financial statements.
PDC
2004-B LIMITED PARTNERSHIP
Statements
of Operations
For the
Years Ended December 31, 2008 and 2007
|
2008
|
2007
|
|||||||
|
Revenues:
|
||||||||
|
Oil
and gas sales
|
$ | 3,763,882 | $ | 3,019,510 | ||||
|
Oil
and gas price risk management gain (loss), net
|
1,324,026 | (171,459 | ) | |||||
|
Total
revenues
|
5,087,908 | 2,848,051 | ||||||
|
Operating
costs and expenses:
|
||||||||
|
Production
and operating costs
|
901,832 | 776,600 | ||||||
|
Direct
costs - general and administrative
|
102,909 | 49,037 | ||||||
|
Depreciation,
depletion and amortization
|
1,397,701 | 1,388,803 | ||||||
|
Accretion
of asset retirement obligations
|
8,780 | 8,304 | ||||||
|
Total
operating costs and expenses
|
2,411,222 | 2,222,744 | ||||||
|
Income
from operations
|
2,676,686 | 625,307 | ||||||
|
Interest
income
|
38,335 | 49,440 | ||||||
|
Net
income
|
$ | 2,715,021 | $ | 674,747 | ||||
|
Net
income allocated to partners
|
$ | 2,715,021 | $ | 674,747 | ||||
|
Less: Managing
General Partner interest in net income
|
543,004 | 134,949 | ||||||
|
Net
income allocated to Investor Partners
|
$ | 2,172,017 | $ | 539,798 | ||||
|
Net
income per Investor Partner unit
|
$ | 2,414 | $ | 600 | ||||
|
Investor
Partner units outstanding
|
899.94 | 899.94 | ||||||
See
accompanying notes to financial statements.
PDC
2004-B LIMITED PARTNERSHIP
Statements
of Partners' Equity
For the
Years Ended December 31, 2008 and 2007
|
Managing
|
||||||||||||
|
Investor
|
General
|
|||||||||||
|
Partners
|
Partner
|
Total
|
||||||||||
|
Balance,
December 31, 2006
|
$ | 12,946,634 | $ | 3,236,662 | $ | 16,183,296 | ||||||
|
Distributions
to partners
|
(1,920,225 | ) | (475,222 | ) | (2,395,447 | ) | ||||||
|
Net
income
|
539,798 | 134,949 | 674,747 | |||||||||
|
Balance,
December 31, 2007
|
11,566,207 | 2,896,389 | 14,462,596 | |||||||||
|
Distributions
to partners
|
(2,377,810 | ) | (594,451 | ) | (2,972,261 | ) | ||||||
|
Net
income
|
2,172,017 | 543,004 | 2,715,021 | |||||||||
|
Balance,
December 31, 2008
|
$ | 11,360,414 | $ | 2,844,942 | $ | 14,205,356 | ||||||
See
accompanying notes to financial statements.
PDC
2004-B LIMITED PARTNERSHIP
Statements
of Cash Flows
For the
Years Ended December 31, 2008 and 2007
|
2008
|
2007
|
|||||||
|
Cash
flows from operating activities:
|
||||||||
|
Net
income
|
$ | 2,715,021 | $ | 674,747 | ||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||
|
Depreciation,
depletion and amortization
|
1,397,701 | 1,388,803 | ||||||
|
Accretion
of asset retirement obligations
|
8,780 | 8,304 | ||||||
|
Unrealized
(gain) loss on derivative transactions
|
(1,253,712 | ) | 343,367 | |||||
|
Changes
in operating assets and liabilities:
|
||||||||
|
Decrease
in accounts receivable
|
217,549 | 255,174 | ||||||
|
Increase
in oil inventory
|
(21,608 | ) | - | |||||
|
Increase
in other assets
|
(7,464 | ) | - | |||||
|
(Increase)
decrease in accounts payable and accrued
expenses
|
(6,224 | ) | 26,894 | |||||
|
Increase
in due from Managing General Partner, Net
|
(59,479 | ) | (290,016 | ) | ||||
|
Net
cash provided by operating activities
|
2,990,564 | 2,407,273 | ||||||
|
Cash
flows from investing activities:
|
||||||||
|
Capital
expenditures for oil and gas properties
|
(7,659 | ) | - | |||||
|
Proceeds
from Colorado tax refund on oil and gas properties
|
37,461 | - | ||||||
|
Net
cash provided by investing activities
|
29,802 | - | ||||||
|
Cash
flows from financing activities:
|
||||||||
|
Distributions
to Partners
|
(2,972,261 | ) | (2,395,447 | ) | ||||
|
Net
cash used in financing activities
|
(2,972,261 | ) | (2,395,447 | ) | ||||
|
Net
increase in cash and cash equivalents
|
48,105 | 11,826 | ||||||
|
Cash
and cash equivalents, beginning of year
|
43,507 | 31,681 | ||||||
|
Cash
and cash equivalents, end of year
|
$ | 91,612 | $ | 43,507 | ||||
See
accompanying notes to financial statements.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Note 1 -
Organization
The PDC
2004-B Limited Partnership (the “Partnership” or the “Registrant”) was organized
as a limited partnership on July 28, 2004, in accordance with the laws of the
State of West Virginia for the purpose of engaging in the exploration and
development of oil and natural gas properties. Business operations of
the Partnership commenced on July 28, 2004, upon closing of an offering for the
sale of Partnership units.
Purchasers
of partnership units subscribed to and fully paid for 4.77 units of limited
partner interests and 895.17 units of additional general partner interests at
$20,000 per unit. As of December 31, 2008, there were 672 Investor
Partners. Petroleum Development Corporation (PDC) has been designated
the Managing General Partner of the Partnership and has a 20% ownership in the
Partnership. Throughout the term of the Partnership, revenues, costs,
and cash distributions are allocated 80% to the limited and additional general
partners (collectively, the “Investor Partners”), which are shared pro rata
based upon the amount of their investment in the Partnership, and 20% to the
Managing General Partner. Through June 30, 2009, the Managing General
Partner has repurchased 17.02 units of Partnership interests from Investor
Partners at an average price of $9,955 per unit.
Upon
completion of the drilling phase of the Partnership's wells, all additional
general partners units were converted into units of limited partner interests
and thereafter became limited partners of the Partnership.
In
accordance with the terms of the Limited Partnership Agreement (the
“Agreement”), the Managing General Partner manages all activities of the
Partnership and acts as the intermediary for substantially all Partnership
transactions.
Executive Drilling
Program
Executive
officers of the Managing General Partner are eligible to invest in a
Board-approved executive drilling program, as approved by the Board of
Directors. These executive officers may profit from their
participation in the executive drilling program because they invest in wells at
cost and do not have to pay drilling compensation, management fees or broker
commissions and therefore obtain an interest in the wells at a reduced price
than that which is generally charged to the investing partners in a
partnership. Investor partners participating in drilling through a
partnership are generally charged a profit or markup above the cost of the
wells, management fees and commissions. See Note 3, Transactions with Managing General
Partner and Affiliates.
Through
the executive drilling program, certain former executive officers of PDC have
invested in the wells developed by PDC in which the Partnership
invests. The executive program allowed PDC to sell working interests
to PDC executive officers in the wells that PDC developed for the
Partnership. Participating officers thereby own parallel undivided
working interests in all of the wells that the Partnership has invested
in. Prior to the funding of the Partnership, each executive officer
who chose to participate in the executive program advised PDC of the dollar
amount of their investment participation, and thereby acquired a working
interest in the wells in which the Partnership acquired a working interest, the
acquired working interest being parallel to the working interest of the
Partnership and the investor partners. The officers’ percentage in
each well is proportionate to the Partnership’s working interest among all of
the Partnership’s wells based upon the officers’ investment
amount. PDC may also sell working interests in these wells, also
prior to the funding of the Partnership, to other parties unaffiliated with
PDC. The aggregate ownership percentage of these former executive
officers ranges from .1269% to .145% of each well in the
Partnership. The Board believes that having the executive officers
invest in wells with PDC and other investor partners helps to create a
commonality of interests much like share ownership creates a commonality of
interests between the shareholders and executive officers.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Note 2 -
Summary of Significant
Accounting Policies
Basis of
Presentation
The
financial statements include only those assets, liabilities and results of
operations of the partners which relate to the business of the
Partnership. The statements do not include any assets, liabilities,
revenues or expenses attributable to any of the partners' other
activities.
Cash and Cash
Equivalents
The
Partnership considers all highly liquid investments with original maturities of
three months or less to be cash equivalents. The Partnership
maintains substantially all of its cash and cash equivalents in a bank account
at one financial institution. Prior to October 3, 2008, the balance
in the Partnership’s account was insured by Federal Deposit Insurance
Corporation, or FDIC, up to $100,000. As a result of the Emergency
Economic Stability Act, the FDIC limit was raised to $250,000 effective October
3, 2008 through December 31, 2009 and subsequently extended through December 31,
2013. At times, the Partnership’s account balance may exceed FDIC
limits. The Partnership has not experienced losses in any such
accounts and limits its exposure to credit loss by placing its cash and cash
equivalents with high-quality financial institutions.
Accounts Receivable and
Allowance for Doubtful Accounts
The
Partnership’s accounts receivable are from purchasers of oil and natural gas
production. The Partnership sells substantially all of its oil and
natural gas to customers who purchase oil and natural gas from other
partnerships managed by the Partnership’s Managing General
Partner. Inherent to the Partnership’s industry is the concentration
of oil and natural gas sales made to few customers. This industry
concentration has the potential to impact the Partnership’s overall exposure to
credit risk, either positively or negatively, in that its customers may be
similarly affected by changes in economic, industry or other
conditions.
As of
December 31, 2008 and 2007, the Partnership did not record an allowance for
doubtful accounts. Historically, neither PDC nor any of the other
partnerships managed by the Partnership’s Managing General Partner have
experienced significant losses on accounts receivable. The Managing
General Partner periodically reviews accounts receivable for credit risks
resulting from changes in the financial condition of its
customers. The Partnership did not incur any losses on accounts
receivable for the years ended December 31, 2008 and 2007.
Due from (to) Managing
General Partner – Other, Net
The
Managing General Partner transacts business on behalf of the
Partnership. Other than oil and natural gas revenues which have not
been received by the Managing General Partner at the balance sheet date and the
Partnership’s portion of unexpired derivatives instruments, which are included
in separate balance sheet captions, all other unsettled transactions with PDC
and its affiliates are recorded net on the balance sheet under the caption “Due
from (to) Managing General Partner – other, net” and are more fully described in
Note 3 Transactions with
Managing General Partner and Affiliates. In addition, certain
amounts recorded by the Partnership as assets in the account “Due from (to)
Managing General Partner – other, net” include amounts that are being held as
restricted cash by the Managing General Partner, on behalf of the Partnership,
for which PDC serves as Managing General Partner.
Additionally,
certain amounts representing royalties on Partnership production through 2008,
which will be deducted from future Partner distributions, were recorded by the
Partnership as liabilities in the account “Due from (to) Managing General
Partner-other, net.” These amounts, which total approximately $18,000
including legal fees of approximately $1,000 as of December 31, 2008, represent
the Partnership’s share of the court approved royalty litigation payment and
settlement, more fully described in Note 9, Commitments and
Contingencies.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
On behalf
of and to the benefit of the Partnership and other partnerships for which PDC
serves as Managing General Partner, the Managing General Partner maintains a
margin deposit with counterparties on outstanding derivative contracts and also
maintains bonds in the form of certificates of deposit for the plugging and
abandoning of wells as required by various governmental
agencies. Since these deposits represent general obligations of the
Managing General Partner and are not specific and identifiable as obligations of
the Partnership, no amounts are recorded by the Partnership related to these
contingent deposits.
Inventories
Oil
inventories are stated at the lower of average lifting cost or market, and are
removed at carrying value.
Oil and Natural Gas
Properties
The
Partnership accounts for its oil and natural gas properties (the “Properties”)
under the successful efforts method of accounting. Costs of proved developed
producing properties, successful exploratory wells and development dry hole
costs are depreciated or depleted by the unit-of-production method based on
estimated proved developed oil and natural gas reserves. Property
acquisition costs are depreciated or depleted on the unit-of-production method
based on estimated proved oil and natural gas reserves. The
Partnership obtains new reserve reports from independent petroleum engineers
annually as of December 31. See Supplemental Oil and Gas Information
– Unaudited, Net Proved Oil
and Gas Reserves for additional information regarding the Partnership’s
reserve reporting. In accordance with the Agreement, all capital
contributed to the Partnership after deducting syndication costs and a one-time
management fee is to be used solely for the drilling of oil and natural gas
wells. Accordingly, all such funds were advanced to the Managing
General Partnership as of December 31, 2004. The Partnership does not
maintain an inventory of undrilled leases.
Partnership
estimates of proved reserves are based on quantities of oil and gas that
engineering and geological analysis demonstrates, with reasonable certainty, to
be recoverable from established reservoirs in the future under current operating
and economic conditions. Independent petroleum engineers prepare the annual
reserve and economic evaluation of all properties on a well-by-well
basis. Additionally, the Partnership adjusts oil and gas reserves for
major well rework or abandonment during the year as needed. The process of
estimating and evaluating oil and gas reserves is complex, requiring significant
decisions in the evaluation of available geological, geophysical, engineering
and economic data. The data for a given property may also change substantially
over time as a result of numerous factors, including additional development
activity, evolving production history and a continual reassessment of the
viability of production under changing economic conditions. As a result,
revisions in existing reserve estimates occur from time to time. Although every
reasonable effort is made to ensure that reserve estimates reported represent
our most accurate assessments possible, the subjective decisions and variances
in available data for various properties increase the likelihood of significant
changes in these estimates over time. Because estimates of reserves
significantly affect our depreciation, depletion and amortization (“DD&A”)
expense, a change in the Partnership’s estimated reserves could have an effect
on the Partnership’s net income.
In
accordance with Statement of Financial Accounting Standards, SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Partnership assesses its proved oil
and gas properties for possible impairment, upon a triggering event, by
comparing net capitalized costs to estimated undiscounted future net cash flows
on a field-by-field basis using estimated production based upon prices at which
the Partnership reasonably estimates the commodity to be sold. The
estimates of future prices may differ from current market prices of oil and
natural gas. Downward revisions in estimates to the Partnership’s
reserve quantities, expectations of falling commodity prices or rising operating
costs could result in a triggering event and therefore a possible impairment of
the Partnership’s oil and natural gas properties. If net capitalized
costs exceed undiscounted future net cash flows, impairment is based on
estimated fair value utilizing a future discounted cash flow analysis and is
measured by the amount by which the net capitalized costs exceed their fair
value. Due to the significant reduction in oil and natural gas prices
during the fourth quarter of 2008 and the availability of new reserve
information, the Partnership reviewed its proved oil and natural gas properties
for impairment at December 31, 2008. The Partnership did not incur any
impairment loss as a result of this review.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Revenue
Recognition
Sales of
natural gas are recognized when natural gas has been delivered to a custody
transfer point, persuasive evidence of a sales arrangement exists, the rights
and responsibility of ownership pass to the purchaser upon delivery, collection
of revenue from the sale is reasonably assured, and the sales price is fixed or
determinable. Natural gas is sold by the Managing General Partner
under contracts with terms ranging from one month up to the life of the
well. Virtually all of the Managing General Partner’s contracts
pricing provisions are tied to a market index with certain adjustments based on,
among other factors, whether a well delivers to a gathering or transmission
line, quality of natural gas and prevailing supply and demand conditions, so
that the price of the natural gas fluctuates to remain competitive with other
available gas supplies.
The
Partnership currently uses the “Net-Back” method of accounting for
transportation arrangements of natural gas sales. The Managing
General Partner sells the Partnership’s natural gas at the wellhead, collects a
price, and recognizes revenues based on the wellhead sales price since
transportation costs downstream of the wellhead are incurred by the
Partnership’s customers and reflected in the wellhead price.
Sales of
oil are recognized when persuasive evidence of a sales arrangement exists, the
oil is verified as produced and is delivered from storage tanks at well
locations to a purchaser, collection of revenue from the sale is reasonably
assured and the sales price is determinable. The Partnership is
currently able to sell all the oil that it can produce under existing sales
contracts with petroleum refiners and marketers. The Partnership does
not refine any of its oil production.
The
Partnership’s crude oil production is sold to purchasers at or near the
Partnership’s wells under short-term purchase contracts at prices and in
accordance with arrangements that are customary in the oil
industry. The Partnership sold natural gas and oil to three primary
customers, DCP Midstream LP (“DCP”), Teppco Crude Oil, LP (“Teppco”) and
Williams Production RMT (“Williams”), which accounted for 7%, 23% and 70%,
respectively, of the Partnership’s total natural gas and oil sales for the year
ended December 31, 2008. These same three customers accounted for
11%, 25% and 64%, respectively, of the Partnership’s total natural gas and oil
sales for the year ended December 31, 2007.
The
Partnership presents any taxes collected from customers and remitted to a
government agency on a net basis in its statements of operations in accordance
with EITF 06-3, How Taxes
Collected from Customers and Remitted to Governments Should be Presented in the
Income Statement.
Asset Retirement
Obligations
The
Partnership applies the provisions of SFAS No. 143, Accounting for Asset Retirement
Obligations and Financial Accounting Standards Board, or FASB,
Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations, and accounts for
asset retirement obligations by recording the fair value of its plugging and
abandonment obligations when incurred, which is at the time the well is
completely drilled. Upon initial recognition of an asset retirement
obligation, the Partnership increases the carrying amount of the long-lived
asset by the same amount as the liability. Over time, the asset
retirement obligations are accreted, over the estimated life of the related
asset, for the change in their present value. The initial capitalized
costs are depleted over the useful lives of the related assets, through charges
to DD&A expense. If the fair value of the estimated asset
retirement obligation changes, an adjustment is recorded to both the asset
retirement obligation and the asset retirement cost. Revisions in estimated
liabilities can result from revisions of estimated inflation rates, escalating
retirement costs and changes in the estimated timing of settling asset
retirement obligations. See Note 8, Asset Retirement Obligations
for a reconciliation of asset retirement obligation activity.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Derivative Financial
Instruments
The
Partnership accounts for derivative financial instruments in accordance with
Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative
Instruments and Certain Hedging Activities, as amended.
The
Partnership has elected not to designate any of the Partnership’s derivative
instruments as hedges. Accordingly, the Partnership recognizes all
derivative instruments as either assets or liabilities on its balance sheets at
fair value. Changes in the fair values of these derivatives allocated
to the Partnership are recorded in the Partnership’s statements of
operations. Changes in the fair value of derivative instruments
related to the Partnership’s oil and gas sales activities are recorded in “Oil
and gas price risk management, net.”
See Note
4, Fair Value of Financial
Instruments and Note 5, Derivative Financial
Instruments, for a discussion of the Partnership’s derivative fair value
measurements and a summary fair value table of open positions as of December 31,
2008 and 2007.
Income
Taxes
Since the
taxable income or loss of the Partnership is reported in the separate tax
returns of the individual investor partners, no provision has been made for
income taxes by the Partnership.
Production Tax
Liability
The
Partnership is responsible for production taxes which are primarily made up of
severance and property taxes to be paid to the states and counties in which the
Partnership produces oil and natural gas. The Partnership’s share of these taxes
is expensed to the account “Production and operating costs.” The
Partnership’s production taxes payable are included in the caption “Accounts
payable and accrued expenses” on the Partnership’s balance sheets.
Use of
Estimates
The
Partnership has made a number of estimates and assumptions relating to the
reporting of assets and liabilities and revenues and expenses and the disclosure
of contingent assets and liabilities to prepare these Partnership financial
statements in conformity with accounting principles generally accepted in the
United States of America. Actual results could differ from those estimates.
Estimates which are particularly significant to the financial statements include
estimates of oil and natural gas reserves, future cash flows from oil and
natural gas properties which are used in assessing impairment of long-lived
assets, estimated production and severance taxes, asset retirement obligations,
and valuation of derivative instruments.
Recently Adopted Accounting
Standards
The
Partnership adopted the provisions of SFAS No. 157, Fair Value Measurements,
effective January 1, 2008. SFAS No. 157 defines fair value,
establishes a framework for measuring fair value and expands disclosures related
to fair value measurements. SFAS No. 157 applies broadly to financial and
nonfinancial assets and liabilities that are measured at fair value under other
authoritative accounting pronouncements, but does not expand the application of
fair value accounting to any new circumstances. In February 2008, the
Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”)
FAS No. 157-2, Effective Date
of FASB Statement No. 157, which delayed the effective date of SFAS No.
157 by one year (to January 1, 2009) for nonfinancial assets and liabilities,
except those that are recognized or disclosed at fair value in the financial
statements on a recurring basis (at least annually). Nonfinancial
assets and liabilities for which the Partnership has not applied the provisions
of SFAS No. 157 include those initially measured at fair value, including the
Partnership’s asset retirement obligations. As of the adoption date,
the Partnership has applied the provisions of SFAS No. 157 to its recurring
measurements and the impact was not material to the Partnership’s underlying
fair values and no amounts were recorded relative to the cumulative effect of a
change in accounting principle. Effective January 1, 2009, the
Partnership will adopt the provisions of FAS No. 157 with respect to
nonfinancial assets and liabilities as delayed by FSP 157-2. The
adoption of FSP 157-2 is not expected to have a material impact on the
Partnership’s financial statements. See Note 4, Fair Value of Financial
Instruments
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
In
October 2008, the FASB issued FSP FAS No. 157-3, Determining the Fair Value of a
Financial Asset in a Market That Is Not Active, which applies to
financial assets within the scope of accounting pronouncements that require or
permit fair value measurements in accordance with SFAS No. 157. This FSP
clarifies the application of SFAS No. 157 in a market that is not active and
defines additional key criteria in determining the fair value of a financial
asset when the market for that financial asset is not active. FSP FAS
No. 157-3 was effective upon issuance and did not have a material impact on the
Partnership’s financial statements.
In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities. SFAS No. 159 permits
entities to choose to measure, at fair value, many financial instruments and
certain other items that are not currently required to be measured at fair
value. The objective is to improve financial reporting by providing
entities with the opportunity to mitigate volatility in reported earnings caused
by measuring related assets and liabilities differently without having to apply
complex hedge accounting provisions. SFAS No. 159 establishes
presentation and disclosure requirements designed to facilitate comparisons
between entities that choose different measurement attributes for similar types
of assets and liabilities. The statement became effective for the
Partnership on January 1, 2008. The Partnership has not and does not
intend to measure additional financial assets and liabilities at fair
value.
In April
2007, the FASB issued FASB Interpretation (“FIN”) No. 39-1, Amendment of FASB Interpretation No.
39, to amend certain portions of Interpretation
39. FIN 39-1 replaces the terms “conditional contracts” and “exchange
contracts” in Interpretation 39 with the term “derivative instruments” as
defined in Statement 133. FIN 39-1 also amends Interpretation 39 to
allow for the offsetting of fair value amounts for the right to reclaim cash
collateral or receivable, or the obligation to return cash collateral or
payable, arising from the same master netting arrangement as the derivative
instruments. FIN 39-1 applies to fiscal years beginning after
November 15, 2007, with early adoption permitted. The January 1, 2008
adoption of FSP FIN 39-1 had no impact on the Partnership’s financial
statements.
Recently Issued Accounting
Standards
In
December 2007, the FASB issued FAS No. 141 (revised 2007), Business Combinations (“FAS
No. 141(R)”). FAS No. 141(R) requires an acquirer to recognize the
assets acquired, the liabilities assumed and any noncontrolling interest in the
acquiree at their acquisition-date fair values. FAS No. 141(R) also
requires disclosure of the information necessary for investors and other users
to evaluate and understand the nature and financial effect of the business
combination. Additionally, FAS No. 141(R) requires that
acquisition-related costs be expensed as incurred. The provisions of
FAS No. 141(R) will become effective for acquisitions completed on or after
January 1, 2009; however, the income tax provisions of FAS No. 141(R) will
become effective as of that date for all acquisitions, regardless of the
acquisition date. FAS No. 141(R) amends FAS No. 109, Accounting for Income Taxes,
to require the acquirer to recognize changes in the amount of its deferred tax
benefits recognizable due to a business combination either in income from
continuing operations in the period of the combination or directly in
contributed capital, depending on the circumstances. FAS No. 141(R)
further amends FAS No. 109 and FASB Interpretation No. (“FIN”) 48, Accounting for Uncertainty in Income
Taxes, to require, subsequent to a prescribed measurement period, changes
to acquisition-date income tax uncertainties to be reported in income from
continuing operations and changes to acquisition-date acquiree deferred tax
benefits to be reported in income from continuing operations or directly in
contributed capital, depending on the circumstances. In April 2009,
the FASB issued FSP FAS No. 141(R)-1, Accounting for Assets Acquired and
Liabilities Assumed in a Business Combination That Arise from
Contingencies (“FSP 141(R)-1”), amending the guidance of FAS No. 141(R)
to require that assets acquired and liabilities assumed in a business
combination that arise from contingencies be recognized at fair value if fair
value can be reasonably estimated and if not, the asset and liability would
generally be recognized in accordance with FAS No. 5, Accounting for Contingencies,
and FASB Interpretation No. 14, Reasonable Estimation of the Amount
of a Loss. Further, FSP 141(R)-1 requires that certain
acquired contingencies be treated as contingent consideration and measured both
initially and subsequently at fair value. The Partnership will adopt
the provisions of FAS No. 141(R) and FSP 141(R)-1 effective January 1, 2009, for
which the provisions will be applied prospectively in the Partnership’s
accounting for future acquisitions, if any. The adoption is expected
to have no impact on the Partnership’s financial statements.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
In
December 2007, the FASB issued FAS No. 160, Non-controlling Interests in
Consolidated Financial Statements—An Amendment of ARB No. 51 (“FAS No.
160”). FAS No. 160 requires the accounting and reporting for minority
interests to be recharacterized as non-controlling interests and classified as a
component of equity. Additionally, FAS No. 160 establishes reporting
requirements that provide sufficient disclosures which clearly identify and
distinguish between the interests of the parent and the interests of the
non-controlling owners. The Partnership will adopt the provisions of
FAS No. 160 effective January 1, 2009. The adoption is expected to
have no impact on the Partnership’s financial
statements.
In March
2008, the FASB issued FAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities—An Amendment of FASB Statement No.
133, which changes the disclosure requirements for derivative instruments
and hedging activities. Enhanced disclosures are required to provide
information about (a) how and why an entity uses derivative instruments, (b) how
derivative instruments and related hedged items are accounted for under
Statement 133 and its related interpretations and (c) how derivative instruments
and related hedged items affect an entity’s financial position, financial
performance and cash flows. The Partnership will adopt the provisions
of FAS No. 161 effective January 1, 2009. The adoption of FAS No. 161
is not expected to have a material impact on the Partnership’s financial
statements. For more information on the Partnership’s derivative
accounting, see Note 5, Derivative Financial
Instruments.
On April
9, 2009, the FASB issued the following amendments to the fair value measurement
and disclosure standards:
|
|
·
|
FSP
No. FAS 157-4, Determining Fair Value When
the Volume and Level of Activity for the Asset or Liability Have
Significantly Decreased and Identifying Transactions That Are Not
Orderly (“FSP 157-4”)
|
|
|
·
|
FSP
No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair
Value of Financial Instruments (“FSP 107-1/APB
28-1”)
|
FSP 157-4
affirms that the objective of fair value when the market for an asset is not
active is the price that would be received to sell the asset in an orderly
transaction; clarifies and includes additional factors for determining whether
there has been a significant decrease in market activity for an asset when the
market for that asset is not active; eliminates the proposed presumption that
all transactions are distressed (not orderly) unless proven otherwise and
instead requires an entity to base its conclusion about whether a transaction
was not orderly on the weight of the evidence; requires an entity to disclose a
change in valuation technique (and the related inputs) resulting from the
application of the FSP and to quantify its effects, if practicable; and applies
to all fair value measurements when appropriate.
FSP
107-1/APB 28-1 amends FAS No. 107, Disclosures about Fair Value of
Financial Instruments, to require an entity to provide disclosures about
fair value of financial instruments in interim financial
information. This FSP also amends Accounting Principles Board (“APB”)
Opinion No. 28, Interim
Financial Reporting, to require those disclosures in summarized financial
information at interim reporting periods. Pursuant to this FSP, a
reporting entity shall include disclosures about the fair value of its financial
instruments whenever it issues summarized financial information for interim
reporting periods. In addition, an entity shall disclose in the body
or in the accompanying notes of its summarized financial information for interim
reporting periods and in its financial statements for annual reporting periods
the fair value of all financial instruments for which it is practicable to
estimate that value, whether recognized or not recognized in the statement of
financial position, as required by SFAS No. 107.
Both FSP
157-4 and FSP 107-1/APB 28-1 are effective for interim and annual reporting
periods ending after June 15, 2009, with early adoption permitted for periods
ending after March 15, 2009. However, early adoption is allowed only
if certain FSPs are early adopted together: an entity early adopting FSP 157-4
must also early adopt FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of
Other-Than-Temporary Impairments (“FSP 115-2/124-2”) and an entity early
adopting FSP 107-1/APB 28-1 must also elect to early adopt FSP 157-4 and FSP
115-2/124-4. The Partnership does not expect these FSPs to have a
significant impact on the Partnership’s financial statements when adopted on
April 1, 2009.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
In
January 2009, the SEC published its final rule, Modernization of Oil and Gas
Reporting, which modifies the SEC’s reporting and disclosure rules for
oil and natural gas reserves. The most notable changes of the final rule
include the replacement of the single day period-end pricing for valuing oil and
natural gas reserves with a 12-month average of the first day of the month price
for each month within the reporting period. The final rule also permits
voluntary disclosure of probable and possible reserves, a disclosure previously
prohibited by SEC rules. The revised reporting and disclosure requirements
are effective for the Partnership’s Annual Report on Form 10-K for the year
ended December 31, 2009. Early adoption is not permitted. The
Partnership is evaluating the impact that adoption of this final rule will have
on the Partnership’s financial statements, related disclosure and management’s
discussion and analysis.
In May
2009, the FASB issued FAS No. 165, Subsequent Events (“FAS No.
165”). FAS No. 165 establishes general standards of accounting for
and disclosure of events that occur after the balance sheet date but before
financial statements are issued. Specifically, FAS No. 165 sets forth
the period after the balance sheet date during which management of a reporting
entity should evaluate events or transactions that may occur for potential
recognition or disclosure in the financial statements, the circumstances under
which an entity should recognize events or transactions occurring after the
balance sheet date in its financial statements, and the disclosures that an
entity should make about events or transactions that occurred after the balance
sheet date. FAS No. 165 is effective for interim or annual periods
ending after June 15, 2009, and is applied prospectively. The
Partnership will adopt FAS No. 165 as of June 30, 2009.
In June
2009, the FASB issued FAS No. 167, Amendments to FASB Interpretation
No. 46(R), to improve financial reporting by enterprises involved with
variable interest entities by addressing (1) the effects on certain provisions
of FIN 46 (revised December 2003) (“FIN 46(R)”), Consolidation of Variable Interest
Entities, as a result of the elimination of the qualifying
special-purpose entity concept in FAS No. 166, Accounting for Transfers of
Financial Assets, and (2) constituent concerns about the application of
certain key provisions of FIN 46(R), including those in which the accounting and
disclosures under the Interpretation do not always provide timely and useful
information about an enterprise’s involvement in a variable interest
entity. This statement is effective for financial statements issued
for fiscal years beginning after November 15, 2009, with earlier adoption
prohibited. The Partnership is evaluating the impact that the
adoption of FAS No. 167 will have on the Partnership’s financial statements,
related disclosure and management’s discussion and analysis.
In June
2009, the FASB issued FAS No. 168, The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting
Principles. This standard replaces FAS No. 162, The Hierarchy of Generally Accepted
Accounting Principles, and establishes only two levels of U.S. GAAP,
authoritative and non-authoritative. The FASB Accounting Standards
Codification (the “Codification”) will become the source of authoritative,
nongovernmental U.S. generally accepted accounting principles (“GAAP”), except
for rules and interpretive releases of the SEC, which are sources of
authoritative GAAP for SEC registrants. All other non-grandfathered,
non-SEC accounting literature not included in the Codification will become
non-authoritative. This standard is effective for financial
statements issued for fiscal years and interim periods ending after September
15, 2009. As the Codification was not intended to change or alter
existing GAAP, the Partnership does not expect the adoption to have a material
impact on the Partnership’s financial statements.
Note 3 -
Transactions with
Managing General Partner and Affiliates
The
Managing General Partner transacts business on behalf of the Partnership under
the authority of the D&O Agreement. Revenues and other cash
inflows received on behalf of the Partnership are distributed to the Partners
net of (after deducting) corresponding operating costs and other cash outflows
incurred on behalf of the Partnership. The fair value of the
Partnership’s portion of unexpired derivative instruments is recorded on the
balance sheet under the captions “Due from Managing General Partner–derivatives”
in the case of net unrealized gains or “Due to Managing General
Partner–derivatives” in the case of net unrealized losses. Realized
gains or losses from derivative transactions that have not yet been distributed
to the Partnership are included in the balance sheet captions “Due from Managing
General Partner-other, net” or “Due to Managing General Partner-other, net,”
respectively. Undistributed realized gains amounted to $350,255 and
$28,401 as of December 31, 2008 and 2007, respectively. Undistributed
oil and natural gas revenues collected by the Managing General Partner from the
Partnership’s customers of $258,733 and $286,249 as of December 31, 2008 and
2007, respectively, are included in the balance sheet caption “Due from Managing
General Partner - other, net.” All other unsettled transactions
between the Partnership and the Managing General Partner are recorded net on the
balance sheet under the caption “Due to or from Managing General Partner –
other, net.”
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
The
following table presents transactions with the Managing General Partner and its
affiliates for years ended December 31, 2008 and 2007. “Well
operations and maintenance” and “Gathering, compression and processing fees” are
included in “Production and operating costs” on the Statements of
Operations.
|
December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Well
operations and maintenance (1)
|
$ | 439,410 | $ | 387,167 | ||||
|
Gathering,
compression and processing fees (2)
|
122,767 | 137,180 | ||||||
|
Direct
costs - general and administrative (3)
|
102,909 | 49,037 | ||||||
|
Cash
distributions (4)
|
615,901 | 479,277 | ||||||
In
accordance with the Drilling and Operating Agreement (“D&O Agreement”), the
Partnership paid its proportionate share of the cost of drilling and completing
each well as follows:
|
|
a)
|
The
cost of the prospect; and
|
|
|
b)
|
The
intangible well costs for each well completed and placed in production, an
amount equal to the depth of the well in feet at its deepest penetration
as recorded by the drilling contractor multiplied by the “intangible
drilling and completion cost” in the D&O Agreement, plus the actual
extra completion cost of zones completed in excess of the cost of the
first zone and actual additional costs incurred in the event that an
intermediate or third string of surface casing is run, rig mobilization
and trucking costs, the additional cost for directional drilling and drill
stem testing, sidetracking, fishing of drilling tools;
and
|
|
|
c)
|
The
tangible costs of drilling and completing the partnership wells and of
gathering pipelines necessary to connect the well to the nearest
appropriate sales point or delivery
point.
|
(1) Under
the D&O Agreement, the Managing General Partner, as operator of the wells,
receives payments for well charges and lease operating supplies and maintenance
expenses from the Partnership when the wells begin producing.
Well charges. The Managing
General Partner receives reimbursement at actual cost for all direct expenses
incurred on behalf of the Partnership, monthly well operating charges for
operating and maintaining the wells during producing operations at a competitive
rate, and monthly administration charge for Partnership activities.
During
the production phase of operations, the Managing General Partner as the operator
receives a monthly fee for each producing well based upon competitive industry
rates for operations and field supervision and $75 for Partnership-related
general and administrative expenses that include accounting, engineering and
management. The Managing General Partner as operator bills
non-routine operations and administration costs to the Partnership at its
cost. The Managing General Partner may not benefit by
inter-positioning itself between the Partnership and the actual provider of
operator services. In no event is any consideration received for
operator services duplicative of any consideration or reimbursement received
under the Agreement.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
The well
operating charges cover all normal and regularly recurring operating expenses
for the production, delivery, and sale of natural gas and oil, such
as:
|
|
·
|
well
tending, routine maintenance, and
adjustment;
|
|
|
·
|
reading
meters, recording production, pumping, maintaining appropriate books and
records; and
|
|
|
·
|
preparing
production related reports to the Partnership and government
agencies.
|
The well
supervision fees do not include costs and expenses related to:
|
|
·
|
the
purchase or repairs of equipment, materials, or third-party
services;
|
|
|
·
|
the
cost of compression and third-party gathering services, or gathering
costs;
|
|
|
·
|
brine
disposal; and
|
|
|
·
|
rebuilding
of access roads.
|
These
costs are charged at the invoice cost of the materials purchased or the
third-party services performed.
Lease Operating Supplies and
Maintenance Expense. The Managing General Partner and its
affiliates may enter into other transactions with the Partnership for services,
supplies and equipment during the production phase of the Partnership, and is
entitled to compensation at competitive prices and terms as determined by
reference to charges of unaffiliated companies providing similar services,
supplies and equipment. Management believes these transactions were
on terms no less favorable than could have been obtained from non-affiliated
third parties.
(2) Under
the Agreement, the Managing General Partner is responsible for gathering,
compression, processing and transporting the gas produced by the Partnership to
interstate pipeline systems, local distribution companies, and/or end-users in
the area from the point the natural gas from the well is commingled with natural
gas from other wells. In such a case, the Managing General Partner
uses gathering systems already owned by PDC or PDC constructs the necessary
facilities if no such line exists. In such a case, the Partnership
pays a gathering, compression and processing fee directly to the Managing
General Partner at competitive rates. If a third-party gathering
system is used, the Partnership pays the gathering fee charged by the
third-party gathering the gas.
(3) The
Managing General Partner is reimbursed by the Partnership for all direct costs
expended by them on the Partnership’s behalf for administrative and professional
fees, such as legal expenses, audit fees and engineering fees for reserve
reports.
(4) The
Agreement provides for the allocation of cash distributions 80% to the Investors
Partners and 20% to the Managing General Partner. The cash
distributions during 2008 and 2007 include $21,450 and $4,055, respectively, for
Investor Partner units repurchased by PDC. For additional disclosure regarding
the allocation of cash distributions, refer to Note 6, Partners’ Equity and Cash
Distributions.
Additionally,
refer to Note 5, Derivative
Financial Instruments for derivative transactions between the Partnership
and the Managing General Partner.
The
Partnership holds record title in its name to the working interest in each
well. PDC provides an assignment of working interest to the
Partnership for the well bore prior to the spudding the well and effective the
date of the spudding of the well, in accordance with the D&O
Agreement. Upon completion of the drilling of all of the Partnership
wells, these assignments are recorded in the applicable
county. Investor Partners rely on PDC to use its best judgment to
obtain appropriate title to these working interests. Provisions of
the Agreement relieve PDC from any error in judgment with respect to the waiver
of title defects. PDC takes those steps it deems necessary to assure
that title to the leases is acceptable for purposes of the
Partnership.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Note 4 -
Fair Value
Measurements
Determination of Fair Value.
The Partnership determines the fair value of its assets and liabilities, unless
specifically excluded, pursuant to FAS No. 157. FAS No. 157 defines
fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date.
FAS No.
157 establishes a fair value hierarchy that requires an entity to maximize the
use of observable inputs and minimize the use of unobservable inputs when
measuring fair value. The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3). In
some cases, the inputs used to measure fair value might fall in different levels
of the fair value hierarchy. The lowest level input that is
significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy. Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or liability, and
may affect the valuation of the assets and liabilities and their placement
within the fair value hierarchy levels. The three levels of inputs
that may be used to measure fair value are defined as:
|
|
·
|
Level 1 –
Quoted prices (unadjusted) in active markets for identical assets or
liabilities. Included in Level 1 would be commodity derivative
instruments for New York Mercantile Exchange (“NYMEX”) natural gas
swaps.
|
|
|
·
|
Level 2 –
Inputs other than quoted prices included within Level 1 that are either
directly or indirectly observable for the asset or liability, including
(i) quoted prices for similar assets or liabilities in active markets,
(ii) quoted prices for identical or similar assets or liabilities in
inactive markets, (iii) inputs other than quoted prices that are
observable for the asset or liability and (iv) inputs that are derived
from observable market data by correlation or other
means.
|
|
|
·
|
Level 3 –
Unobservable inputs for the asset or liability, including situations where
there is little, if any, market activity for the asset or
liability. Included in Level 3 are the Partnership’s commodity
based and basis protection derivative instruments for Colorado Interstate
Gas, or CIG, based fixed-price natural gas swaps, collars and floors, oil
swaps, and natural gas basis protection
swaps.
|
Derivative Financial
Instruments. The Partnership measures fair value based upon
quoted market prices, where available. The valuation determination
includes: (1) identification of the inputs to the fair value methodology through
the review of counterparty statements and other supporting documentation, (2)
determination of the validity of the source of the inputs, (3) corroboration of
the original source of inputs through access to multiple quotes, if available,
or other information and (4) monitoring changes in valuation methods and
assumptions. The methods described above may produce a fair value
calculation that may not be indicative of future fair values. The
valuation determination also gives consideration to nonperformance risk on
Partnership liabilities in addition to nonperformance risk on PDC’s own business
interests and liabilities, as well as the credit standing of derivative
instrument counterparties. The Managing General Partner primarily
uses two investment grade financial institutions as counterparties to its
derivative contracts, who hold the majority of the Managing General Partner’s
derivative assets. The Managing General Partner has evaluated the
credit risk of the Partnership’s derivative assets from counterparties holding
its derivative assets using relevant credit market default rates, giving
consideration to amounts outstanding for each counterparty and the duration of
each outstanding derivative position. Based on the Managing General
Partner’s evaluation, the Partnership has determined that the impact of
counterparty non-performance on the fair value of the Partnership’s derivative
instruments is insignificant. As of December 31, 2008, no valuation
allowance has been recorded by the Partnership. Furthermore, while
the Managing General Partner believes these valuation methods are appropriate
and consistent with that used by other market participants, the use of different
methodologies, or assumptions, to determine the fair value of certain financial
instruments could result in a different estimate of fair value.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
The
following table presents, by hierarchy level, the Partnership’s derivative
financial instruments, including both current and non-current portions, measured
at fair value for the year ended December 31, 2008.
|
Level 3
|
Total
|
|||||||
|
Assets:
|
||||||||
|
Commodity
based derivatives
|
$ | 1,315,396 | $ | 1,315,396 | ||||
|
Total
assets
|
1,315,396 | 1,315,396 | ||||||
|
Liabilities:
|
||||||||
|
Basis
protection derivative contracts
|
(100,327 | ) | (100,327 | ) | ||||
|
Total
liabilities
|
(100,327 | ) | (100,327 | ) | ||||
|
Net
fair value of derivatives
|
$ | 1,215,069 | $ | 1,215,069 | ||||
The
following table sets forth the changes of the Partnership’s Level 3 derivative
financial instruments measured on a recurring basis:
|
Year
ended
|
||||
|
December 31, 2008
|
||||
|
Fair
value, net asset (liability), beginning of year
|
$ | (38,643 | ) | |
|
Changes
in fair value included in Oil and gas price risk management,
net
|
1,324,026 | |||
|
Purchases,
sales, issuances and settlements, net
|
(70,314 | ) | ||
|
Fair
value, net asset, end of year
|
$ | 1,215,069 | ||
See Note
5, Derivative Financial
Instruments, for additional disclosure related to the Partnership’s
derivative financial instruments.
Non-Derivative Assets and
Liabilities. The carrying values of the financial instruments
comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable
and accrued expenses” and “Due to (from) Managing General Partner-other, net”
approximate fair value due to the short-term maturities of these
instruments.
In
accordance with FAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Partnership assesses its proved oil
and gas properties for possible impairment, upon a triggering event, by
comparing net capitalized costs to estimated undiscounted future net cash flows
on a field-by-field basis using estimated production based upon prices at which
the Partnership reasonably estimates the commodity to be sold. The
estimates of future prices may differ from current market prices of oil and
natural gas. Certain events, including but not limited to, downward
revisions in estimates to the Partnership’s reserve quantities, expectations of
falling commodity prices or rising operating costs could result in a triggering
event and, therefore, a possible impairment of the Partnership’s oil and natural
gas properties. If net capitalized costs exceed undiscounted future
net cash flows, the measurement of impairment is based on estimated fair value
utilizing a future discounted cash flow analysis and is measured by the amount
by which the net capitalized costs exceed their fair value. Due to
the significant reduction in oil and natural gas prices during the fourth
quarter of 2008 and the availability of new reserve information, the Partnership
reviewed its proved oil and natural gas properties for impairment at December
31, 2008. The Partnership did not incur any impairment loss as a
result of this review. Although cash flow estimates used by the
Partnership are based on the relevant information available at the time the
estimates are made, estimates of future cash flows are, by nature, highly
uncertain and may vary significantly from actual results.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Note 5 -
Derivative Financial
Instruments
The
Partnership is exposed to the effect of market fluctuations in the prices of oil
and natural gas. Price risk represents the potential risk of loss
from adverse changes in the market price of oil and natural gas
commodities. The Managing General Partner employs established
policies and procedures to manage the risks associated with these market
fluctuations using derivative instruments. Partnership policy
prohibits the use of oil and natural gas derivative instruments for speculative
purposes.
The
Partnership has elected not to designate any of the Partnership’s derivative
instruments as hedges. Accordingly, the Partnership recognizes all
derivative instruments as either assets or liabilities on its balance sheets at
fair value. Changes in the fair value of those derivative instruments
allocated to the Partnership are recorded in the Partnership’s statements of
operations. Changes in the fair value of derivative instruments
related to the Partnership’s oil and gas sales activities are recorded in “Oil
and gas price risk management, net.”
Valuation
of a contract’s fair value is performed internally and, while the Managing
General Partner uses common industry practices to develop the Partnership’s
valuation techniques, changes in pricing methodologies or the underlying
assumptions could result in different fair values. See Note 4, Fair Value Measurements, for
a discussion of how the Managing General Partner determines the fair value of
the Partnership’s derivative instruments.
As of
June 30, 2009, the Managing General Partner had derivative contracts in place
for a portion of the Partnership’s anticipated production through 2012 for a
total of 567 MMbtu of natural gas and 8 MBbls of crude oil.
Derivative
Strategies. The Partnership’s results of operations and
operating cash flows are affected by changes in market prices for oil and
natural gas. To mitigate a portion of the exposure to adverse market
changes, the Managing General Partner has entered into various derivative
contracts.
For
Partnership oil and gas sales, the Managing General Partner enters into, for the
Partnership’s production, derivative contracts to protect against price declines
in future periods. While these derivatives are structured to reduce
exposure to changes in price associated with the derivative commodity, they also
limit the benefit the Partnership might otherwise have received from price
increases in the physical market. The Partnership believes the
derivative instruments in place continue to be effective in achieving the risk
management objectives for which they were intended.
As of
December 31, 2008, the Partnership’s oil and natural gas derivative instruments
were comprised of commodity collars, commodity swaps and basis protection
swaps.
|
|
·
|
Collars
contain a fixed floor price (put) and ceiling price (call). If
the market falls below the fixed put strike price, PDC, as Managing
General Partner, receives the market price from the purchaser and receives
the difference between the put strike price and market price from the
counterparty. If the market price exceeds the fixed call strike
price, PDC, as Managing General Partner, receives the market price from
the purchaser and pays the difference between the call strike price and
market price to the counterparty. If the market price is
between the call and put strike price, no payments are due to or from the
counterparty.
|
|
|
·
|
Swaps
are arrangements that guarantee a fixed price. If the market
price is below the fixed contract price, PDC, as Managing General Partner,
receives the market price from the purchaser and receives the difference
between the market price and the fixed contract price from the
counterparty. If the market price is above the fixed contract price,
PDC, as Managing General Partner, receives the market price from the
purchaser and pays the difference between the market price and the fixed
contract price to the counterparty.
|
|
|
·
|
Basis
protection swaps are arrangements that guarantee a price differential for
natural gas from a specified delivery point. For CIG basis
protection swaps, which have negative differentials to NYMEX, PDC, as
Managing General Partner, receives a payment from the counterparty if the
price differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the stated
terms of the contract.
|
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
At
December 31, 2008 and 2007, the Partnership had the following asset and
liability positions related to its open commodity-based derivative instruments
for a portion of the Partnership’s oil and natural gas production.
|
December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Derivative
net assets (liabilities)
|
||||||||
|
Fixed-price
natural gas swaps
|
$ | 471,991 | $ | - | ||||
|
Natural
gas collars
|
507,175 | 27,758 | ||||||
|
Natural
gas basis protection swaps
|
(100,327 | ) | - | |||||
|
Natural
gas floors
|
- | 697 | ||||||
|
Fixed-price
oil swaps
|
336,230 | (67,098 | ) | |||||
|
Estimated
net fair value of derivative instruments
|
$ | 1,215,069 | $ | (38,643 | ) | |||
At
December 31, 2008 and 2007, the maximum term for the derivative positions listed
above is 60 months and 12 months, respectively.
The
following table identifies the fair value of commodity based derivatives as
classified in the Partnership’s balance sheets:
|
December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
Classification
in the Balance Sheets
|
||||||||
|
Fair
value of current assets
|
||||||||
|
Due
from Managing General Partner-derivatives
|
$ | 995,593 | $ | 30,002 | ||||
|
Fair
value of other assets-long term
|
||||||||
|
Due
from Managing General Partner-derivatives
|
319,803 | - | ||||||
| 1,315,396 | 30,002 | |||||||
|
Fair
value of current liabilities
|
||||||||
|
Due
to Managing General Partner-derivatives
|
- | 68,645 | ||||||
|
Fair
value of other liabilities-long term
|
||||||||
|
Due
to Managing General Partner-derivatives
|
100,327 | - | ||||||
|
Net
fair value of derivative instruments - asset (liability)
|
$ | 1,215,069 | $ | (38,643 | ) | |||
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
The
following table identifies the changes in the fair value of commodity based
derivatives as reflected in the Partnership’s statements of
operations:
|
Years Ended
|
||||||||
|
2008
|
2007
|
|||||||
|
Realized
gains (losses)
|
||||||||
|
Oil
|
$ | (45,042 | ) | $ | (3,604 | ) | ||
|
Natural
Gas
|
115,356 | 175,512 | ||||||
|
Total
realized gain, net
|
70,314 | 171,908 | ||||||
|
Unrealized
gain (loss)
|
1,253,712 | (343,367 | ) | |||||
|
Oil
and gas price risk management gain (loss), net
|
$ | 1,324,026 | $ | (171,459 | ) | |||
Concentration of Credit Risk.
A significant portion of the Partnership’s liquidity is concentrated in
derivative instruments that enables the Partnership to manage a portion of its
exposure to price volatility from producing oil and natural
gas. These arrangements expose the Partnership to credit risk of
nonperformance by the counterparties. The Managing General Partner
primarily uses two financial institutions, who are also lenders in the Managing
General Partner’s credit facility agreement, as counterparties to the derivative
contracts.
Note 6 -
Partners’ Equity and
Cash Distributions
Partners’
Equity
A unit
represents the individual interest of an individual investor partner in the
Partnership. No public market exists or will develop for the
units. While units of the Partnership are transferable, assignability
of the units is limited, requiring the consent of the Managing General
Partner. Further, individual investor partners may request that the
Managing General Partner repurchase units pursuant to the repurchase
program.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Allocation of Partners’
Interest
The table
below summarizes the participation of the Investor Partners and the Managing
General Partner in the revenues and costs of the Partnership.
|
Managing
|
||||||||
|
Investor
|
General
|
|||||||
|
Partners
|
Partner
|
|||||||
|
Partnership
Revenue:
|
||||||||
|
Oil
and gas sales
|
80 | % | 20 | % | ||||
|
Preferred
cash distribution (a)
|
100 | % | 0 | % | ||||
|
Oil
and gas price risk management gain (loss)
|
80 | % | 20 | % | ||||
|
Sale
of productive properties
|
80 | % | 20 | % | ||||
|
Sale
of equipment
|
0 | % | 100 | % | ||||
|
Sale
of undeveloped leases
|
80 | % | 20 | % | ||||
|
Interest
income
|
80 | % | 20 | % | ||||
|
Partnership
Costs:
|
||||||||
|
Organization
costs (b)
|
0 | % | 100 | % | ||||
|
Broker-dealer
commissions and expenses/syndication costs (b)
|
100 | % | 0 | % | ||||
|
Cost
of oil and gas properties: (c)
|
||||||||
|
Undeveloped
lease costs
|
0 | % | 100 | % | ||||
|
Tangible
well costs
|
0 | % | 100 | % | ||||
|
Intangible
drilling costs
|
100 | % | 0 | % | ||||
|
Other
costs and expenses:
|
||||||||
|
Management
fee (d)
|
100 | % | 0 | % | ||||
|
Production
and operating costs (e)
|
80 | % | 20 | % | ||||
|
Depreciation,
depletion and amortization expense
|
80 | % | 20 | % | ||||
|
Accretion
of asset retirement obligations
|
80 | % | 20 | % | ||||
|
Direct
costs - general and administrative (f)
|
80 | % | 20 | % | ||||
|
|
(a)
|
To
the extent that Investor Partners receive preferred cash distributions,
the allocations for Investor Partners will be increased accordingly and
the allocation for the Managing General Partner will likewise be
decreased. See Performance Standard
Obligation of Managing General Partner
below.
|
|
|
(b)
|
The
Managing General Partner paid all legal, accounting, printing, and filing
fees associated with the organization of the Partnership and the offering
of units and is allocated 100% of these costs. The Investor
Partners paid all dealer manager commissions, discounts, and due diligence
reimbursements and are allocated 100% of these
costs.
|
|
|
(c)
|
These
allocations are for tax reporting purposes and do not impact cash
distributions or Partners’ equity.
|
|
|
(d)
|
Represents
a one-time fee paid to the Managing General Partner on the day the
Partnership was funded equal to 1-1/2% of total investor
subscriptions.
|
|
|
(e)
|
Represents
operating costs incurred after the completion of productive wells,
including monthly per-well charges paid to the Managing General
Partner.
|
|
|
(f)
|
The
Managing General Partner receives monthly reimbursement from the
Partnership for direct costs – general and administrative costs incurred
by the Managing General Partner on behalf of the
Partnership.
|
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
The
following table presents the allocation of net income to the Investor Partners
and the Managing General Partner for each of the periods presented.
|
Year
ended December 31,
|
||||||||
|
2008
|
2007
|
|||||||
| Net income allocated to Investor Partners | ||||||||
|
80%
of Net Income allocable to the Partners
|
$ | 2,172,017 | $ | 539,798 | ||||
| Net income allocated to Managing General Partner | ||||||||
|
20%
of Net Income allocable to the Partners
|
543,004 | 134,949 | ||||||
|
Net
income allocated to Partners
|
$ | 2,715,021 | $ | 674,747 | ||||
Performance Standard
Obligation of Managing General Partner
The
Agreement provides for the enhancement of investor cash distributions if the
Partnership does not meet a performance standard defined in the Agreement during
the first 10 years of operations beginning 6 months after the close of the
Partnership. In general, if the average annual rate of return to the
Investor Partners is less than 12.5% of their subscriptions, the allocation rate
of cash distributions to Investor Partners will increase up to one-half of the
Managing General Partner’s interest until the average annual rate increases to
12.5%, with a corresponding decrease to the Managing General
Partner. The 12.5% rate of return is calculated by including the
estimated benefit of a 25% income tax savings on the investment in the first
year in addition to the cash distributions made to the Investor Partners as a
percentage of the investment, divided by the number of years since the closing
of the Partnership less six months. For the years ended December 31,
2008 and 2007, no obligation of the Managing General Partner arose under this
provision.
Unit Repurchase
Provisions
Investor
Partners may request that the Managing General Partner repurchase units at any
time beginning with the third anniversary of the first cash distribution of the
Partnership. The repurchase price is set at a minimum of four times
the most recent twelve months of cash distributions from
production. The Managing General Partner is conditionally obligated
to purchase, in any calendar year, Investor Partner units aggregating to 10% of
the initial subscriptions if requested by an individual investor partner,
subject to its financial ability to do so and upon receipt of opinions of
counsel that the repurchase will not cause the Partnership to be treated as a
“publically traded partnership” or result in the termination of the Partnership
for federal income tax purposes. Repurchase requests are fulfilled by
the Managing General Partner on a first-come, first-serve basis.
In the
first quarter of 2008, the Managing General Partner repurchased a total of 0.5
units during February 2008, the first month unit repurchases were eligible under
the program, at an average price of $9,230 per unit and 0.25 units during March
2008 at an average price of $7,340 per unit. Second quarter unit
repurchases included the April 2008 repurchase of 0.5 units at an average price
per unit of $7,330 and May 2008 repurchases of 0.25 units at an average price
per unit of $7,520. Remaining 2008 repurchases were comprised of
fourth quarter repurchases of 1.0 unit at an average price of $9,295 per unit in
October and 2.5 units at an average price of $9,748 per unit in
December.
First
quarter 2009 unit repurchases include 1.0 unit repurchased at an average price
of $10,345 per unit during February and 0.5 units repurchased at an average
price of $10,670 per unit during March. Second quarter repurchases in
April 2009, were 4.25 units repurchased at an average price of $10,794 per
unit. There have been no third quarter repurchases through July
2009.
In
addition to the above repurchase program, individual investor partners
periodically offer and PDC repurchases units on a negotiated basis before the
third anniversary of the date of the first cash distribution.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Cash
Distributions
The
Agreement requires the Managing General Partner to distribute cash available for
distribution not less frequently than quarterly. The Managing General
Partner will determine and distribute, if funds are available for distribution,
cash on a monthly basis. The Managing General Partner will make cash
distributions of 80% to the Investor Partners and 20% to the Managing General
Partner throughout the term of the Partnership. The Partnership has
paid cash distributions each month since February 2005. Distributions
for the years ended December 31, 2008 and 2007 were $2,972,261, and $2,395,447,
respectively.
Note 7 -
Oil and Gas
Properties
The
Partnership is engaged solely in oil and natural gas activities, all of which
are located in the continental United States. Drilling operations
began upon funding on July 2004 with advances made to the Managing General
Partner for all planned drilling and completion costs for the Partnership by
December 31, 2004. Costs capitalized for these activities at December
31, 2008 and 2007 are as follows:
|
2008
|
2007
|
|||||||
|
Leasehold
costs
|
$ | 240,400 | $ | 240,400 | ||||
|
Development
costs
|
19,865,698 | 19,895,500 | ||||||
|
Oil
and gas properties, successful efforts method, at cost
|
20,106,098 | 20,135,900 | ||||||
|
Less:
Accumulated depreciation, depletion and amortization
|
(8,156,676 | ) | (6,758,975 | ) | ||||
|
Oil
and gas properties, net
|
$ | 11,949,422 | $ | 13,376,925 | ||||
Included
in Development Costs are the estimated costs associated with the Partnership’s
asset retirement obligations discussed in Note 8, Asset Retirement
Obligations.
Note 8 -
Asset Retirement
Obligations
Changes
in the carrying amount of asset retirement obligations associated with the
Partnership’s working interest in oil and natural gas properties are as
follows:
|
2008
|
2007
|
|||||||
|
Balance
at beginning of year
|
$ | 152,707 | $ | 144,403 | ||||
|
Accretion
expense
|
8,780 | 8,304 | ||||||
|
Balance
at end of year
|
$ | 161,487 | $ | 152,707 | ||||
If the
fair value of the estimated asset retirement obligation changes, an adjustment
is recorded to both the asset retirement obligation and the asset retirement
cost.
Note 9 -
Commitments and
Contingencies
Colorado Royalty
Settlement. On May 29, 2007, Glen Droegemueller, individually
and as representative plaintiff on behalf of all others similarly situated,
filed a class action complaint against the Managing General Partner in the
District Court, Weld County, Colorado alleging that the Managing General Partner
underpaid royalties on natural gas produced from wells operated by the Managing
General Partner in parts of the State of Colorado (the “Droegemueller
Action”). The plaintiff sought declaratory relief and to recover an
unspecified amount of compensation for underpayment of royalties paid by us
pursuant to leases. The Managing General Partner removed the case to
Federal Court on June 28, 2007. On October 10, 2008, the court
preliminarily approved a settlement agreement between the plaintiffs and the
Managing General Partner on behalf of itself and the Partnership. Although
the Partnership was not named as a party in the suit, the lawsuit states that it
relates to all wells operated by the Managing General Partner, which includes a
majority of the Partnership’s 16 wells in the Wattenberg field. The
portion of the settlement relating to the Partnership’s wells for all periods
through December 31, 2008 that has been expensed by the Partnership is
approximately $18,000, including associated legal costs of approximately
$1,000. This entire settlement of $17,713 was deposited by the
Managing General Partner into an escrow account on November 3,
2008. Notice of the settlement was mailed to members of the class
action suit in the fourth quarter of 2008. The final settlement was
approved by the court on April 7, 2009. Settlement distribution
checks were mailed in July 2009. During September 2009, all
settlement costs were passed through to the Partners and any required judicial
action from the settlement of the suit was implemented in this
distribution.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Financial Statements
Colorado Stormwater
Permit. On December 8, 2008, the Managing General Partner
received a Notice of Violation /Cease and Desist Order (the “Notice”) from the
Colorado Department of Public Health and Environment, related to the stormwater
permit for the Garden Gulch Road. The Managing General Partner
manages this private road for Garden Gulch LLC. The Managing General
Partner is one of eight users of this road, all of which are oil and gas
companies operating in the Piceance region of Colorado. Operating
expenses, including this fine, if any, are allocated among the eight users of
the road based upon their respective usage. The Partnership has seven
wells in this region. The Notice alleges a deficient and/or
incomplete stormwater management plan, failure to implement best management
practices and failure to conduct required permit inspections. The Notice
requires corrective action and states that the recipient shall cease and desist
such alleged violations. The Notice states that a violation could result
in civil penalties up to $10,000 per day. The Managing General Partner’s
responses were submitted on February 6, 2009 and April 8, 2009. Given the
preliminary stage of this proceeding and the inherent uncertainty in
administrative actions of this nature, the Managing General Partner is unable to
predict the ultimate outcome of this administrative action at this
time.
Derivative
Contracts. The Partnership is exposed to oil and natural gas
price fluctuations on underlying sales contracts should the counterparties to
the Managing General Partner’s derivative instruments not
perform. Nonperformance is not anticipated. The Managing
General Partner has had no counterparty default losses to date.
PDC
2004-B LIMITED PARTNERSHIP
Supplemental
Oil and Natural Gas Information - Unaudited
Costs Incurred in Oil and
Natural Gas Property Development Activities
During
2008, the Partnership received an approximately $37,000 refund from the State of
Colorado for state sales taxes charged during prior years on well tubing and
casing purchases during the Partnership’s drilling operations, which have
subsequently been determined to be tax-exempt. The refund has been
accounted for as a reduction of the costs of oil and gas properties previously
capitalized. The Partnership periodically invests in equipment which
supports enhanced hydrocarbon recovery, treatment, delivery and measurement or
environmental protection which totaled approximately $8,000 in
2008.
Net Proved Oil
and
Natural Gas
Reserves
Our
proved oil and natural gas reserves have been estimated by independent petroleum
engineers. Ryder Scott Company, L.P. prepared Partnership reserve reports
estimating proved reserves at December 31, 2008 and 2007. These reserve
estimates have been prepared in compliance with professional standards and the
reserves definitions prescribed by the SEC.
Proved
reserves are the estimated quantities of oil and natural gas that geologic and
engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions. Estimates of proved reserves may change, either positively or
negatively, as additional information becomes available and as contractual,
economic and political conditions change. The Partnership’s net proved reserve
estimates have been adjusted as necessary to reflect all contractual agreements,
royalty obligations and interests owned by others at the time of the
estimate.
Proved
developed reserves are the quantities of oil and natural gas expected to be
recovered through existing wells with existing equipment and operating methods.
Proved undeveloped reserves are those reserves expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for completion. In some cases, proved
undeveloped reserves may require substantial new investments in additional wells
and related facilities.
The
following Partnership reserve estimates present the estimate of the proved gas
and oil reserves and net cash flows of the Partnership’s properties all of which
are located in the United States. The Managing General Partner’s
management emphasizes that reserve estimates are inherently imprecise and that
estimates of new discoveries are more imprecise than those of producing gas and
oil properties. Accordingly, the estimates are expected to change as
future information becomes available.
PDC
2004-B LIMITED PARTNERSHIP
Supplemental
Oil and Natural Gas Information - Unaudited
Below are
the net quantities of net proved reserves of the Partnership’s properties as of
December 31, 2008 and 2007.
|
Oil (MBbl)
|
||||||||
|
2008
|
2007
|
|||||||
|
Proved
reserves:
|
||||||||
|
Beginning
of year
|
229 | 223 | ||||||
|
Revisions
of previous estimates
|
38 | 19 | ||||||
|
Production
|
(10 | ) | (13 | ) | ||||
|
End
of year, December 31
|
257 | 229 | ||||||
|
Gas (MMcf)
|
||||||||
| 2008 | 2007 | |||||||
|
Proved
reserves:
|
||||||||
|
Beginning
of year
|
5,538 | 5,936 | ||||||
|
Revisions
of previous estimates
|
464 | 65 | ||||||
|
Production
|
(446 | ) | (463 | ) | ||||
|
End
of year, December 31
|
5,556 | 5,538 | ||||||
|
As of December 31,
|
||||||||
|
Proved Developed Reserves
|
2008 | 2007 | ||||||
|
Oil
(MBbl)
|
46 | 71 | ||||||
|
Natural
Gas (MMcf)
|
4,390 | 4,906 | ||||||
Definitions
used throughout Supplemental Oil and Gas Information - Unaudited:
|
|
·
|
Bbl
– One barrel or 42 U.S. gallons liquid
volume
|
|
|
·
|
MBbl
– One thousand barrels
|
|
|
·
|
Mcf
– One thousand cubic feet
|
|
|
·
|
Mcfe
– One thousand cubic feet of gas equivalents, based on a ratio of 6 Mcf
for each barrel of oil, which reflects the relative energy
content
|
|
|
·
|
MMcf
– One million cubic feet
|
|
|
·
|
MMcfe
– One million cubic feet of gas
equivalents
|
At
December 31, 2008, the Partnership’s estimated proved oil and natural gas
reserves experienced a net upward revision of previous estimates of 38 MBbls of
oil and 464 MMcfs of natural gas, respectively. This net revision is
the result of an upward revision of proved undeveloped reserves amounting to
approximately 53 MBbls of oil and 534 MMcfs of natural gas, partially offset by
a downward revision of proved developed producing reserves amounting to
approximately 15 MBbls of oil and 70 MMcfs of natural gas,
respectively. The downward revision to proved developed producing
reserves was primarily due to reduced economics resulting from significantly
lower year end oil and natural gas prices and higher per well operating costs at
December 31, 2008. The upward revision to proved undeveloped reserves
was due primarily to an increase in the production curve based upon a detailed
analysis of the results of the Codell zone refractures in the Wattenberg Field
performed by PDC, the Managing General Partner, over the last several
years.
At
December 31, 2007, the Partnership recorded an upward revision to its previous
estimate of proved reserves of approximately 65 MMcf of gas and 19 MBbl of
oil. The revision was primarily due to a decrease of 297 MMcf of gas
and an increase of 17 MBbl of oil due to changes in well performance and its
related upward revision to the wells’ decline curves and increases of 362 MMcf
of gas and 1 MBbl of oil due to commodity price changes.
PDC
2004-B LIMITED PARTNERSHIP
Supplemental
Oil and Natural Gas Information - Unaudited
Standardized Measure of
Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and
Gas Reserves
Summarized
in the following table is information with respect to the standardized measure
of discounted future net cash flows relating to proved oil and gas
reserves. Future cash inflows are computed by applying year-end
prices of oil and gas relating to our proved reserves to the year-end quantities
of those reserves. Future production, development, site restoration and
abandonment costs are derived based on current costs, including production –
related taxes, primarily severance and property, assuming continuation of
existing economic conditions. Future development costs include the
development costs related to recompletions of wells drilled in the Codell
formation, as described in Item 1, Business—Plan of
Operations. Since Partnership taxable income is reported in
the separate tax returns of individual investor partners, no future estimated
income taxes are computed and presented herein.
|
As
of December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Future
estimated revenues
|
$ | 35,997 | $ | 54,777 | ||||
|
Future
estimated production costs
|
(13,558 | ) | (15,848 | ) | ||||
|
Future
estimated development costs
|
(3,207 | ) | (2,852 | ) | ||||
|
Future
net cash flows
|
19,232 | 36,077 | ||||||
|
10%
annual discount for estimated timing of cash flows
|
(9,345 | ) | (17,678 | ) | ||||
|
Standardized
measure of discounted future estimated net cash flows
|
$ | 9,887 | $ | 18,399 | ||||
The
following table summarizes the principal sources of change in the standardized
measure of discounted future estimated net cash flows for the years ended
December 31, 2008 and 2007:
|
Year Ended
December 31,
|
||||||||
|
2008
|
2007
|
|||||||
|
(in
thousands)
|
||||||||
|
Sales
of oil and gas production, net of production costs
|
$ | (2,862 | ) | $ | (2,243 | ) | ||
|
Net
changes in prices and production costs
|
(8,318 | ) | 7,312 | |||||
|
Revisions
of previous quantity estimates
|
1,187 | 820 | ||||||
|
Accretion
of discount
|
1,703 | 1,120 | ||||||
|
Timing
and other
|
(222 | ) | (1,107 | ) | ||||
|
Net
change
|
$ | (8,512 | ) | $ | 5,902 | |||
The data
presented should not be viewed as representing the expected cash flow from, or
current value of, existing proved reserves since the computations are based on a
large number of estimates and arbitrary assumptions. 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 of demand and
governmental control. Actual future prices and costs are likely to be
substantially different from the current prices and costs 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 limitations inherent therein.
PDC
2004-B LIMITED PARTNERSHIP
Supplemental
Oil and Natural Gas Information - Unaudited
The
estimated present value of future cash flows relating to proved reserves is
extremely sensitive to prices used at any measurement period. The
average December 31 price used for each commodity at December 31, 2008 and 2007
is presented below.
|
As of December 31,
|
Oil (per
Bbl)
|
Gas (per
Mcf)
|
||||||
|
2008
|
$ | 38.33 | $ | 4.70 | ||||
|
2007
|
80.12 | 6.58 | ||||||
PDC
2004-B LIMITED PARTNERSHIP
Condensed
Quarterly Balance Sheets
(Unaudited)
|
As of
|
||||||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
|||||||||||||
|
Assets
|
2008
|
2008
|
2008
|
2008 *
|
||||||||||||
|
Current
assets:
|
||||||||||||||||
|
Cash
and cash equivalents
|
$ | 46,065 | $ | 48,315 | $ | 52,098 | $ | 91,612 | ||||||||
|
Accounts
receivable
|
373,243 | 408,041 | 247,765 | 147,587 | ||||||||||||
|
Accounts
receivable - other
|
- | 37,461 | 37,461 | - | ||||||||||||
|
Oil
inventory
|
22,088 | 24,531 | 19,358 | 21,608 | ||||||||||||
|
Due
from Managing General Partner-derivatives
|
15,234 | - | 543,582 | 995,593 | ||||||||||||
|
Due
from Managing General Partner-other, net
|
1,154,921 | 1,321,680 | 1,182,540 | 964,412 | ||||||||||||
|
Total
current assets
|
1,611,551 | 1,840,028 | 2,082,804 | 2,220,812 | ||||||||||||
|
Oil
and gas properties, successful efforts method, at cost
|
20,142,134 | 20,104,673 | 20,104,673 | 20,106,098 | ||||||||||||
|
Less: Accumulated
depreciation, depletion and amortization
|
(7,097,664 | ) | (7,491,786 | ) | (7,810,379 | ) | (8,156,676 | ) | ||||||||
|
Oil
and gas properties, net
|
13,044,470 | 12,612,887 | 12,294,294 | 11,949,422 | ||||||||||||
|
Due
from Managing General Partner-derivatives
|
23,656 | - | 257,145 | 319,803 | ||||||||||||
|
Other
assets
|
12 | 1,098 | 4,281 | 7,464 | ||||||||||||
|
Total
noncurrent assets
|
13,068,138 | 12,613,985 | 12,555,720 | 12,276,689 | ||||||||||||
|
Total
Assets
|
$ | 14,679,689 | $ | 14,454,013 | $ | 14,638,524 | $ | 14,497,501 | ||||||||
|
Liabilities and Partners'
Equity
|
||||||||||||||||
|
Current
liabilities:
|
||||||||||||||||
|
Accounts
payable and accrued expenses
|
$ | 87,942 | $ | 138,352 | $ | 83,030 | $ | 30,331 | ||||||||
|
Due
to Managing General Partner-derivatives
|
395,670 | 689,550 | 69,947 | - | ||||||||||||
|
Total
current liabilities
|
483,612 | 827,902 | 152,977 | 30,331 | ||||||||||||
|
Due
to Managing General Partner-derivatives
|
45,794 | 279,717 | 72,092 | 100,327 | ||||||||||||
|
Asset
retirement obligations
|
154,902 | 157,097 | 159,292 | 161,487 | ||||||||||||
|
Total
liabilities
|
684,308 | 1,264,716 | 384,361 | 292,145 | ||||||||||||
|
Partners'
equity:
|
||||||||||||||||
|
Managing
General Partner
|
2,802,947 | 2,641,730 | 2,854,704 | 2,844,942 | ||||||||||||
|
Limited
Partners - 899.94 units issued and outstanding
|
11,192,434 | 10,547,567 | 11,399,459 | 11,360,414 | ||||||||||||
|
Total
Partners' equity
|
13,995,381 | 13,189,297 | 14,254,163 | 14,205,356 | ||||||||||||
|
Total
Liabilities and Partners' Equity
|
$ | 14,679,689 | $ | 14,454,013 | $ | 14,638,524 | $ | 14,497,501 | ||||||||
*Derived
from audited December 31, 2008 balance sheet contained in the Partnership’s
accompanying financial statements for the year ended December 31, 2008, included
in this report.
See
accompanying notes to unaudited condensed quarterly financial
statements.
PDC
2004-B LIMITED PARTNERSHIP
Condensed
Quarterly Balance Sheets
(Unaudited)
|
As of
|
||||||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
|||||||||||||
|
Assets
|
2007
|
2007
|
2007
|
2007*
|
||||||||||||
|
Current
assets:
|
||||||||||||||||
|
Cash
and cash equivalents
|
$ | 36,463 | $ | 40,104 | $ | 43,598 | $ | 43,507 | ||||||||
|
Accounts
receivable
|
338,104 | 310,039 | 210,305 | 365,136 | ||||||||||||
|
Due
from Managing General Partner-derivatives
|
233,897 | 237,295 | 203,936 | 30,002 | ||||||||||||
|
Due
from Managing General Partner-other, net
|
994,838 | 1,040,246 | 1,039,740 | 821,800 | ||||||||||||
|
Total
current assets
|
1,603,302 | 1,627,684 | 1,497,579 | 1,260,445 | ||||||||||||
|
Oil
and gas properties, successful efforts method, at cost
|
20,135,900 | 20,135,900 | 20,135,900 | 20,135,900 | ||||||||||||
|
Less: Accumulated
depreciation, depletion and amortization
|
(5,760,151 | ) | (6,121,019 | ) | (6,440,680 | ) | (6,758,975 | ) | ||||||||
|
Oil
and gas properties, net
|
14,375,749 | 14,014,881 | 13,695,220 | 13,376,925 | ||||||||||||
|
Due
from Managing General Partner-derivatives
|
- | 63,233 | 14,553 | - | ||||||||||||
|
Due
from Managing General Partner-other, net
|
31,627 | 60,138 | 83,133 | 83,133 | ||||||||||||
|
Total
noncurrent assets
|
14,407,376 | 14,138,252 | 13,792,906 | 13,460,058 | ||||||||||||
|
Total
Assets
|
$ | 16,010,678 | $ | 15,765,936 | $ | 15,290,485 | $ | 14,720,503 | ||||||||
|
Liabilities and Partners'
Equity
|
||||||||||||||||
|
Current
liabilities:
|
||||||||||||||||
|
Accounts
payable and accrued expenses
|
$ | 82,325 | $ | 74,660 | $ | 58,713 | $ | 36,555 | ||||||||
|
Due
to Managing General Partner-derivatives
|
70,671 | 49,379 | 17,271 | 68,645 | ||||||||||||
|
Total
current liabilities
|
152,996 | 124,039 | 75,984 | 105,200 | ||||||||||||
|
Due
to Managing General Partner-derivatives
|
- | 33,900 | 5,097 | - | ||||||||||||
|
Asset
retirement obligations
|
146,479 | 148,555 | 150,631 | 152,707 | ||||||||||||
|
Total
liabilities
|
299,475 | 306,494 | 231,712 | 257,907 | ||||||||||||
|
Partners'
equity:
|
||||||||||||||||
|
Managing
General Partner
|
3,142,244 | 3,095,758 | 3,015,624 | 2,896,389 | ||||||||||||
|
Limited
Partners - 899.94 units issued and outstanding
|
12,568,959 | 12,363,684 | 12,043,149 | 11,566,207 | ||||||||||||
|
Total
Partners' equity
|
15,711,203 | 15,459,442 | 15,058,773 | 14,462,596 | ||||||||||||
|
Total
Liabilities and Partners' Equity
|
$ | 16,010,678 | $ | 15,765,936 | $ | 15,290,485 | $ | 14,720,503 | ||||||||
* Derived
from audited December 31, 2007 balance sheet contained in the Partnership’s Form
10-K for the year ended December 31, 2007.
See
accompanying notes to unaudited condensed quarterly financial
statements.
PDC
2004-B LIMITED PARTNERSHIP
Condensed
Quarterly Statement of Operations
(Unaudited)
|
Quarter Ended
|
||||||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
|||||||||||||
|
2008
|
2008
|
2008
|
2008
|
|||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil
and gas sales
|
$ | 953,636 | $ | 1,480,313 | $ | 923,614 | $ | 406,319 | ||||||||
|
Oil
and gas price risk management gain (loss), net
|
(398,826 | ) | (849,553 | ) | 1,665,769 | 906,636 | ||||||||||
|
Total
revenues
|
554,810 | 630,760 | 2,589,383 | 1,312,955 | ||||||||||||
|
Operating
costs and expenses:
|
||||||||||||||||
|
Production
and operating costs
|
191,687 | 295,585 | 224,979 | 189,581 | ||||||||||||
|
Direct
costs - general and administrative
|
6,804 | 12,556 | 7,426 | 76,123 | ||||||||||||
|
Depreciation,
depletion and amortization
|
338,689 | 394,122 | 318,593 | 346,297 | ||||||||||||
|
Accretion
of asset retirement obligations
|
2,195 | 2,195 | 2,195 | 2,195 | ||||||||||||
|
Total
operating costs and expenses
|
539,375 | 704,458 | 553,193 | 614,196 | ||||||||||||
|
Income
(loss) from operations
|
15,435 | (73,698 | ) | 2,036,190 | 698,759 | |||||||||||
|
Interest
income
|
10,223 | 9,516 | 9,288 | 9,308 | ||||||||||||
|
Net
income (loss)
|
$ | 25,658 | $ | (64,182 | ) | $ | 2,045,478 | $ | 708,067 | |||||||
|
Net
income (loss) allocated to partners
|
$ | 25,658 | $ | (64,182 | ) | $ | 2,045,478 | $ | 708,067 | |||||||
|
Less: Managing
General Partner interest in net income (loss)
|
5,132 | (12,837 | ) | 409,096 | 141,613 | |||||||||||
|
Net
income (loss) allocated to Investor Partners
|
$ | 20,526 | $ | (51,345 | ) | $ | 1,636,382 | $ | 566,454 | |||||||
|
Net
income (loss) per Investor Partner unit
|
$ | 23 | $ | (57 | ) | $ | 1,818 | $ | 629 | |||||||
|
Investor
Partner units outstanding
|
899.94 | 899.94 | 899.94 | 899.94 | ||||||||||||
See
accompanying notes to unaudited condensed quarterly financial
statements
PDC
2004-B LIMITED PARTNERSHIP
Condensed
Quarterly Statements of Operations
(Unaudited)
|
Quarter Ended
|
||||||||||||||||
|
March 31,
|
June 30,
|
September 30,
|
December 31,
|
|||||||||||||
|
2007
|
2007
|
2007
|
2007
|
|||||||||||||
|
Revenues:
|
||||||||||||||||
|
Oil
and gas sales
|
$ | 900,910 | $ | 812,178 | $ | 655,037 | $ | 651,385 | ||||||||
|
Oil
and gas price risk management gain (loss), net
|
(149,148 | ) | 106,463 | 77,589 | (206,363 | ) | ||||||||||
|
Total
revenues
|
751,762 | 918,641 | 732,626 | 445,022 | ||||||||||||
|
Operating
costs and expenses:
|
||||||||||||||||
|
Production
and operating costs
|
195,397 | 193,665 | 208,557 | 178,981 | ||||||||||||
|
Direct
costs - general and administrative
|
- | 15,239 | - | 33,798 | ||||||||||||
|
Depreciation,
depletion and amortization
|
389,979 | 360,868 | 319,661 | 318,295 | ||||||||||||
|
Accretion
of asset retirement obligations
|
2,076 | 2,076 | 2,076 | 2,076 | ||||||||||||
|
Total
operating costs and expenses
|
587,452 | 571,848 | 530,294 | 533,150 | ||||||||||||
|
Income
(loss) from operations
|
164,310 | 346,793 | 202,332 | (88,128 | ) | |||||||||||
|
Interest
income
|
13,339 | 12,276 | 12,052 | 11,773 | ||||||||||||
|
Net
income (loss)
|
$ | 177,649 | $ | 359,069 | $ | 214,384 | $ | (76,355 | ) | |||||||
|
Net
income (loss) allocated to partners
|
$ | 177,649 | $ | 359,069 | $ | 214,384 | $ | (76,355 | ) | |||||||
|
Less: Managing
General Partner interest in net income (loss)
|
35,530 | 71,814 | 42,876 | (15,271 | ) | |||||||||||
|
Net
income (loss) allocated to Investor Partners
|
$ | 142,119 | $ | 287,255 | $ | 171,508 | $ | (61,084 | ) | |||||||
|
Net
income (loss) per Investor Partner unit
|
$ | 158 | $ | 319 | $ | 191 | $ | (68 | ) | |||||||
|
Investor
Partner units outstanding
|
899.94 | 899.94 | 899.94 | 899.94 | ||||||||||||
See
accompanying notes to unaudited condensed quarterly financial
statements.
PDC
2004-B LIMITED PARTNERSHIP
Condensed
Interim Statements of Cash Flows
(Unaudited)
|
Three
|
Six
|
Nine
|
||||||||||
|
Months
Ended
|
Months
Ended
|
Months
Ended
|
||||||||||
|
March
31,
|
June
30,
|
September
30,
|
||||||||||
|
2008
|
2008
|
2008
|
||||||||||
|
Cash
flows from operating activities:
|
||||||||||||
|
Net
income (loss)
|
$ | 25,658 | $ | (38,524 | ) | $ | 2,006,954 | |||||
|
Adjustments
to reconcile net income (loss) to net cash provided by operating
activities:
|
||||||||||||
|
Depreciation,
depletion and amortization
|
338,689 | 732,811 | 1,051,404 | |||||||||
|
Accretion
of asset retirement obligations
|
2,195 | 4,390 | 6,585 | |||||||||
|
Unrealized
loss (gain) on derivative transactions
|
363,931 | 930,624 | (697,331 | ) | ||||||||
|
Changes
in operating assets and liabilities:
|
||||||||||||
|
(Increase)
decrease in accounts receivable
|
(8,107 | ) | (42,905 | ) | 117,371 | |||||||
|
Increase
in accounts receivable - other
|
- | (37,461 | ) | (37,461 | ) | |||||||
|
Increase
in oil inventory
|
(22,088 | ) | (24,531 | ) | (19,358 | ) | ||||||
|
Increase
in other assets
|
(12 | ) | (1,098 | ) | (4,281 | ) | ||||||
|
Increase
in accounts payable and accrued expenses
|
51,387 | 101,797 | 46,475 | |||||||||
|
Increase
in Due from Managing General Partner, net
|
(249,988 | ) | (379,286 | ) | (240,146 | ) | ||||||
|
Net
cash provided by operating activities
|
501,665 | 1,245,817 | 2,230,212 | |||||||||
|
Cash
flows from investing activities:
|
||||||||||||
|
Capital
expenditures for oil and gas properties
|
(6,234 | ) | (6,234 | ) | (6,234 | ) | ||||||
|
Net
cash used in investing activities
|
(6,234 | ) | (6,234 | ) | (6,234 | ) | ||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Distributions
to Partners
|
(492,873 | ) | (1,234,775 | ) | (2,215,387 | ) | ||||||
|
Net
cash used in financing activities
|
(492,873 | ) | (1,234,775 | ) | (2,215,387 | ) | ||||||
|
Net
increase in cash and cash equivalents
|
2,558 | 4,808 | 8,591 | |||||||||
|
Cash
and cash equivalents, beginning of period
|
43,507 | 43,507 | 43,507 | |||||||||
|
Cash
and cash equivalents, end of period
|
$ | 46,065 | $ | 48,315 | $ | 52,098 | ||||||
See
accompanying notes to unaudited condensed quarterly financial
statements.
PDC
2004-B LIMITED PARTNERSHIP
Condensed
Interim Statements of Cash Flows
(Unaudited)
|
Three
|
Six
|
Nine
|
||||||||||
|
Months
Ended
|
Months
Ended
|
Months
Ended
|
||||||||||
|
March
31,
|
June
30,
|
September
30,
|
||||||||||
|
2007
|
2007
|
2007
|
||||||||||
|
Cash
flows from operating activities:
|
||||||||||||
|
Net
income
|
$ | 177,649 | $ | 536,718 | $ | 751,102 | ||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||||
|
Depreciation,
depletion and amortization
|
389,979 | 750,847 | 1,070,508 | |||||||||
|
Accretion
of asset retirement obligations
|
2,076 | 4,152 | 6,228 | |||||||||
|
Unrealized
loss on derivative transactions
|
141,498 | 87,475 | 108,603 | |||||||||
|
Changes
in operating assets and liabilities:
|
||||||||||||
|
Decrease
in accounts receivable
|
282,206 | 310,271 | 410,005 | |||||||||
|
Increase
in accounts payable and accrued expenses
|
72,664 | 64,999 | 49,052 | |||||||||
|
Increase
in Due from Managing General Partner, net
|
(411,548 | ) | (485,467 | ) | (507,956 | ) | ||||||
|
Net
cash provided by operating activities
|
654,524 | 1,268,995 | 1,887,542 | |||||||||
|
Cash
flows from financing activities:
|
||||||||||||
|
Distributions
to Partners
|
(649,742 | ) | (1,260,572 | ) | (1,875,625 | ) | ||||||
|
Net
cash used in financing activities
|
(649,742 | ) | (1,260,572 | ) | (1,875,625 | ) | ||||||
|
Net
increase in cash and cash equivalents
|
4,782 | 8,423 | 11,917 | |||||||||
|
Cash
and cash equivalents, beginning of period
|
31,681 | 31,681 | 31,681 | |||||||||
|
Cash
and cash equivalents, end of period
|
$ | 36,463 | $ | 40,104 | $ | 43,598 | ||||||
See
accompanying notes to unaudited condensed quarterly financial
statements
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
Note 1 -
Basis of
Presentation
The PDC
2004-B Limited Partnership (the “Partnership” or the “Registrant”) was organized
as a limited partnership on July 28, 2004, in accordance with the laws of the
State of West Virginia for the purpose of engaging in the exploration and
development of oil and natural gas properties and commenced business operations
with its funding on July 28, 2004, upon completion of its sale of Partnership
units.
The
accompanying interim financial statements have been prepared without audit in
accordance with accounting principles generally accepted in the United States of
America for interim financial information and the instructions to Form 10-Q and
Regulation S-X, Rule 8-03(a) and (b) of the Securities and Exchange Commission
(“SEC”). Accordingly, pursuant to certain rules and regulations,
certain notes and other financial information included in the accompanying
audited financial statements have been condensed or omitted. In the
Partnership’s opinion, the accompanying interim financial statements contain all
adjustments (consisting of only normal recurring adjustments) necessary to
fairly state the Partnership's financial position and results of operations for
the periods presented.
Note 2 -
Transactions with
Managing General Partner and Affiliates
The
Managing General Partner transacts business on behalf of the
Partnership. Revenues and other cash inflows received on behalf of
the Partnership are distributed to the Partners net of (after deducting)
corresponding operating costs and other cash outflows incurred on behalf of the
Partnership. The fair value of the Partnership’s portion of unexpired
derivative instruments is recorded on the balance sheet under the captions “Due
from Managing General Partner–derivatives” in the case of net unrealized gains
or “Due to Managing General Partner–derivatives” in the case of net unrealized
losses. Undistributed oil and natural gas revenues collected by the
Managing General Partner from the Partnership’s customers of $580,392,
$1,072,273, $675,848 and $258,733 as of March 31, 2008, June 30, 2008, September
30, 2008 and December 31, 2008, respectively, and
$552,396, $502,139, $444,732 and $286,249 at March 31,
2007, June 30, 2007, September 30, 2007 and December 31, 2007, respectively, are
included in the balance sheet caption “Due from Managing General Partner –
other, net.” Realized gains or losses from derivative transactions
that have not yet been distributed to the Partnership are included in the
balance sheet caption “Due from Managing General Partner-other, net” or “Due to
Managing General Partner-other, net,” respectively. All other
unsettled transactions between the Partnership and the Managing General Partner
are also recorded net on the balance sheet under the caption “Due from (to)
Managing General Partner – other, net.”
The
following table presents transactions with the Managing General Partner and its
affiliates during the quarters ended March 31, June 30, September 30 and
December 31, for the years 2008 and 2007. “Well operations and
maintenance” and “Gathering, compression and processing fees” are included in
“Production and operating costs” on the Statements of Operations.
|
Quarter Ended
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
Transaction
|
|
|
|
|
||||||||||||
|
Well
operations and maintenance
|
$ | 72,810 | $ | 118,076 | $ | 115,322 | $ | 133,202 | ||||||||
|
Gathering,
compression and processing fees
|
30,935 | 39,157 | 26,627 | 26,048 | ||||||||||||
|
Direct
costs- general and administrative
|
6,804 | 12,556 | 7,426 | 76,123 | ||||||||||||
|
Cash
distributions*
|
101,585 | 153,456 | 202,894 | 157,966 | ||||||||||||
|
Quarter Ended
|
||||||||||||||||
|
March 31, 2007
|
June 30, 2007
|
September 30, 2007
|
December 31, 2007
|
|||||||||||||
|
Transaction
|
|
|
|
|
||||||||||||
|
Well
operations and maintenance
|
$ | 72,063 | $ | 79,393 | $ | 117,319 | $ | 118,392 | ||||||||
|
Gathering,
compression and processing fees
|
41,009 | 39,612 | 32,525 | 24,034 | ||||||||||||
|
Direct
costs- general and administrative
|
- | 15,239 | - | 33,798 | ||||||||||||
|
Cash
distributions*
|
130,382 | 118,711 | 123,420 | 106,764 | ||||||||||||
*Cash
distributions started in February 2005. Cash distributions include
equity cash distributions on Investor Partner units repurchased by
PDC. For the quarters ended March 31, June 30, September 30 and
December 31, 2008, cash distributions on repurchased Investor Partner units were
$3,011; $5,076; $6,772 and $6,591, respectively. For the quarters
ended March 31, June 30, September 30 and December 31, 2007, cash distributions
on repurchased Investor Partner units were $434; $411; $410 and $2,800,
respectively.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
Note 3 -
Fair Value
Measurements
Determination of Fair Value. The
Partnership determines the fair value of its assets and liabilities, unless
specifically excluded, pursuant to FAS No. 157. FAS No. 157 defines
fair value as the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market participants at
the measurement date.
FAS No.
157 establishes a fair value hierarchy that requires an entity to maximize the
use of observable inputs and minimize the use of unobservable inputs when
measuring fair value. The valuation hierarchy is based upon the
transparency of inputs to the valuation of an asset or liability as of the
measurement date, giving the highest priority to quoted prices in active markets
(Level 1) and the lowest priority to unobservable data (Level 3). In
some cases, the inputs used to measure fair value might fall in different levels
of the fair value hierarchy. The lowest level input that is
significant to a fair value measurement in its entirety determines the
applicable level in the fair value hierarchy. Assessing the
significance of a particular input to the fair value measurement in its entirety
requires judgment, considering factors specific to the asset or liability, and
may affect the valuation of the assets and liabilities and their placement
within the fair value hierarchy levels. The three levels of inputs
that may be used to measure fair value are defined as:
|
|
·
|
Level 1 –
Quoted prices (unadjusted) in active markets for identical assets or
liabilities. Included in Level 1 would be commodity derivative
instruments for New York Mercantile Exchange (“NYMEX”) natural gas
swaps.
|
|
|
·
|
Level 2 –
Inputs other than quoted prices included within Level 1 that are either
directly or indirectly observable for the asset or liability, including
(i) quoted prices for similar assets or liabilities in active markets,
(ii) quoted prices for identical or similar assets or liabilities in
inactive markets, (iii) inputs other than quoted prices that are
observable for the asset or liability and (iv) inputs that are derived
from observable market data by correlation or other
means.
|
|
|
·
|
Level 3 –
Unobservable inputs for the asset or liability, including situations where
there is little, if any, market activity for the asset or
liability. Included in Level 3 are the Partnership’s commodity
based and basis protection derivative instruments for Colorado Interstate
Gas, or CIG, based fixed-price natural gas swaps, collars and floors, oil
swaps, and natural gas basis protection
swaps.
|
Derivative Financial
Instruments. The Partnership measures fair value based upon
quoted market prices, where available. The valuation determination
includes: (1) identification of the inputs to the fair value methodology through
the review of counterparty statements and other supporting documentation, (2)
determination of the validity of the source of the inputs, (3) corroboration of
the original source of inputs through access to multiple quotes, if available,
or other information and (4) monitoring changes in valuation methods and
assumptions. The methods described above may produce a fair value
calculation that may not be indicative of future fair values. The
valuation determination also gives consideration to nonperformance risk on
Partnership liabilities in addition to nonperformance risk on PDC’s own business
interests and liabilities, as well as the credit standing of derivative
instrument counterparties. The Managing General Partner primarily
uses two investment grade financial institutions as counterparties to its
derivative contracts, who hold the majority of the Managing General Partner’s
derivative assets. The Managing General Partner has evaluated the
credit risk of the Partnership’s derivative assets from counterparties holding
its derivative assets using relevant credit market default rates, giving
consideration to amounts outstanding for each counterparty and the duration of
each outstanding derivative position. Based on the Managing General
Partner’s evaluation, the Partnership has determined that the impact of
counterparty non-performance on the fair value of the Partnership’s derivative
instruments is insignificant. Furthermore, while the Managing General
Partner believes these valuation methods are appropriate and consistent with
that used by other market participants, the use of different methodologies, or
assumptions, to determine the fair value of certain financial instruments could
result in a different estimate of fair value.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
The
following table presents the Partnership’s assets and liabilities for each
hierarchy level, including both current and non-current portions, measured at
fair value on a recurring basis for the three months ended March 31, June 30,
September 30 and December 31, 2008:
|
Level 3
|
||||||||||||||||
|
Quarter ended
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
Assets:.
|
||||||||||||||||
|
Commodity
based derivatives
|
$ | 38,890 | $ | - | $ | 800,727 | $ | 1,315,396 | ||||||||
|
Total
assets
|
38,890 | - | 800,727 | 1,315,396 | ||||||||||||
|
Liabilities:
|
||||||||||||||||
|
Commodity
based derivatives
|
(441,464 | ) | (969,267 | ) | (142,039 | ) | - | |||||||||
|
Basis
protection derivative contracts
|
- | - | - | (100,327 | ) | |||||||||||
|
Total
liabilities
|
(441,464 | ) | (969,267 | ) | (142,039 | ) | (100,327 | ) | ||||||||
|
Net
fair value of derivative instruments
|
$ | (402,574 | ) | $ | (969,267 | ) | $ | 658,688 | $ | 1,215,069 | ||||||
The table
below sets forth the changes of the Partnership’s Level 3 fair value
measurements in which derivative asset and liability fair values are presented
on a “net” basis. See Note 4 for additional disclosure related to the
Partnership’s derivative financial instruments.
|
Three months Ended
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
Fair
value, net asset (liability), beginning of period
|
$ | (38,643 | ) | $ | (402,574 | ) | $ | (969,267 | ) | $ | 658,688 | |||||
|
Changes
in fair value included in Oil and gas price risk management,
net
|
(398,826 | ) | (849,553 | ) | 1,665,769 | 906,636 | ||||||||||
|
Purchases,
sales, issuances and settlements, net
|
34,895 | 282,860 | (37,814 | ) | (350,255 | ) | ||||||||||
|
Fair
value, net asset (liability), end of period
|
$ | (402,574 | ) | $ | (969,267 | ) | $ | 658,688 | $ | 1,215,069 | ||||||
See Note
4, Derivative Financial
Instruments, for additional disclosure related to the Partnership’s
derivative financial instruments.
Non-Derivative Assets and
Liabilities. The carrying values of the financial instruments
comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts payable
and accrued expenses” and “Due to (from) Managing General Partner-other, net”
approximate fair value due to the short-term maturities of these
instruments.
In
accordance with FAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Partnership assesses its proved oil
and gas properties for possible impairment, upon a triggering event, by
comparing net capitalized costs to estimated undiscounted future net cash flows
on a field-by-field basis using estimated production based upon prices at which
the Partnership reasonably estimates the commodity to be sold. The
estimates of future prices may differ from current market prices of oil and
natural gas. Certain events, including but not limited to, downward
revisions in estimates to the Partnership’s reserve quantities, expectations of
falling commodity prices or rising operating costs could result in a triggering
event and, therefore, a possible impairment of the Partnership’s oil and natural
gas properties. If net capitalized costs exceed undiscounted future
net cash flows, the measurement of impairment is based on estimated fair value
utilizing a future discounted cash flow analysis and is measured by the amount
by which the net capitalized costs exceed their fair value.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
Note 4 -
Derivative Financial
Instruments
The
Partnership is exposed to the effect of market fluctuations in the prices of oil
and natural gas. Price risk represents the potential risk of loss
from adverse changes in the market price of oil and natural gas
commodities. The Managing General Partner employs established
policies and procedures to manage the risks associated with these market
fluctuations using derivative instruments. Partnership policy
prohibits the use of oil and natural gas derivative instruments for speculative
purposes.
The
Partnership has elected not to designate any of the Partnership’s derivative
instruments as hedges. Accordingly, the Partnership recognizes all
derivative instruments as either assets or liabilities on its balance sheets at
fair value. Changes in the fair value of those derivative instruments
allocated to the Partnership are recorded in the Partnership’s statements of
operations. Changes in the fair value of derivative instruments
related to the Partnership’s oil and gas sales activities are recorded in “Oil
and gas price risk management, net.”
Valuation
of a contract’s fair value is performed internally and, while the Managing
General Partner uses common industry practices to develop the Partnership’s
valuation techniques, changes in pricing methodologies or the underlying
assumptions could result in different fair values. See Note 4, Fair Value Measurements, for
a discussion of how the Managing General Partner determines the fair value of
the Partnership’s derivative instruments.
As of
June 30, 2009, the Managing General Partner had derivative contracts in place
for a portion of the Partnership’s anticipated production through 2012 for a
total of 567 MMbtu of natural gas and 8 MBbls of crude oil.
Derivative
Strategies. The Partnership’s results of operations and
operating cash flows are affected by changes in market prices for oil and
natural gas. To mitigate a portion of the exposure to adverse market
changes, the Managing General Partner has entered into various derivative
contracts.
For
Partnership oil and gas sales, the Managing General Partner enters into, for the
Partnership’s production, derivative contracts to protect against price declines
in future periods. While these derivatives are structured to reduce
exposure to changes in price associated with the derivative commodity, they also
limit the benefit the Partnership might otherwise have received from price
increases in the physical market. The Partnership believes the
derivative instruments in place continue to be effective in achieving the risk
management objectives for which they were intended.
As of
December 31, 2008, the Partnership’s oil and natural gas derivative instruments
were comprised of commodity collars, commodity swaps and basis protection
swaps.
|
|
·
|
Collars
contain a fixed floor price (put) and ceiling price (call). If
the market falls below the fixed put strike price, PDC, as Managing
General Partner, receives the market price from the purchaser and receives
the difference between the put strike price and market price from the
counterparty. If the market price exceeds the fixed call strike
price, PDC, as Managing General Partner, receives the market price from
the purchaser and pays the difference between the call strike price and
market price to the counterparty. If the market price is
between the call and put strike price, no payments are due to or from the
counterparty.
|
|
|
·
|
Swaps
are arrangements that guarantee a fixed price. If the market
price is below the fixed contract price, PDC, as Managing General Partner,
receives the market price from the purchaser and receives the difference
between the market price and the fixed contract price from the
counterparty. If the market price is above the fixed contract price,
PDC, as Managing General Partner, receives the market price from the
purchaser and pays the difference between the market price and the fixed
contract price to the
counterparty.
|
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
|
|
·
|
Basis
protection swaps are arrangements that guarantee a price differential for
natural gas from a specified delivery point. For CIG basis
protection swaps, which have negative differentials to NYMEX, PDC, as
Managing General Partner, receives a payment from the counterparty if the
price differential is greater than the stated terms of the contract and
pays the counterparty if the price differential is less than the stated
terms of the contract.
|
During
2008 and 2007, at the end of the three month periods noted below, the
Partnership had the following asset and liability positions related to its open
commodity-based derivative instruments for a portion of the Partnership’s oil
and natural gas production.
|
As of
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
Derivative
net assets (liabilities)
|
||||||||||||||||
|
Fixed-price
natural gas swaps
|
$ | (284,275 | ) | $ | (414,783 | ) | $ | 497,635 | $ | 471,991 | ||||||
|
Natural
gas collars
|
(31,304 | ) | (20,999 | ) | 285,358 | 507,175 | ||||||||||
|
Natural
gas basis protection swaps
|
- | - | - | (100,327 | ) | |||||||||||
|
Oil
collars
|
(20,503 | ) | - | - | - | |||||||||||
|
Fixed-price
oil swaps
|
(66,492 | ) | (533,485 | ) | (124,305 | ) | 336,230 | |||||||||
|
Estimated
net fair value of derivative instruments
|
$ | (402,574 | ) | $ | (969,267 | ) | $ | 658,688 | $ | 1,215,069 | ||||||
|
As of
|
||||||||||||||||
|
March 31, 2007
|
June 30, 2007
|
September 30, 2007
|
December 31, 2007
|
|||||||||||||
|
Derivative
net assets (liabilities)
|
||||||||||||||||
|
Natural
gas collars
|
$ | (42,402 | ) | $ | 179,535 | $ | 135,985 | $ | 27,758 | |||||||
|
Natural
gas floors
|
204,987 | 37,616 | 60,130 | 697 | ||||||||||||
|
Oil
floors
|
641 | 98 | 6 | - | ||||||||||||
|
Fixed-price
oil swaps
|
- | - | - | (67,098 | ) | |||||||||||
|
Estimated
net fair value of derivative instruments
|
$ | 163,226 | $ | 217,249 | $ | 196,121 | $ | (38,643 | ) | |||||||
At
December 31, 2008 and 2007, the maximum term for the derivative positions listed
above is 60 months and 12 months, respectively.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
The
following table identifies the fair value of commodity based derivatives as
classified in the Partnership’s balance sheets:
|
As of
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
Classification
in the Balance Sheets
|
||||||||||||||||
|
Fair
value of current assets
|
||||||||||||||||
|
Due
from Managing General Partner-derivatives
|
$ | 15,234 | $ | - | $ | 543,582 | $ | 995,593 | ||||||||
|
Fair
value of other assets-long term
|
||||||||||||||||
|
Due
from Managing General Partner-derivatives
|
23,656 | - | 257,145 | 319,803 | ||||||||||||
| 38,890 | - | 800,727 | 1,315,396 | |||||||||||||
|
Fair
value of current liabilities
|
||||||||||||||||
|
Due
to Managing General Partner-derivatives
|
395,670 | 689,550 | 69,947 | - | ||||||||||||
|
Fair
value of other liabilities-long term
|
||||||||||||||||
|
Due
to Managing General Partner-derivatives
|
45,794 | 279,717 | 72,092 | 100,327 | ||||||||||||
| 441,464 | 969,267 | 142,039 | 100,327 | |||||||||||||
|
Net
fair value of derivative instruments - (liability) asset
|
$ | (402,574 | ) | $ | (969,267 | ) | $ | 658,688 | $ | 1,215,069 | ||||||
|
As of
|
||||||||||||||||
|
March 31, 2007
|
June 30, 2007
|
September 30, 2007
|
December 31, 2007
|
|||||||||||||
|
Classification
in the Balance Sheets
|
||||||||||||||||
|
Fair
value of current assets
|
||||||||||||||||
|
Due
from Managing General Partner-derivatives
|
$ | 233,897 | $ | 237,295 | $ | 203,936 | $ | 30,002 | ||||||||
|
Fair
value of other assets-long term
|
||||||||||||||||
|
Due
from Managing General Partner-derivatives
|
- | 63,233 | 14,553 | - | ||||||||||||
| 233,897 | 300,528 | 218,489 | 30,002 | |||||||||||||
|
Fair
value of current liabilities
|
||||||||||||||||
|
Due
to Managing General Partner-derivatives
|
70,671 | 49,379 | 17,271 | 68,645 | ||||||||||||
|
Fair
value of other liabilities-long term
|
||||||||||||||||
|
Due
to Managing General Partner-derivatives
|
- | 33,900 | 5,097 | - | ||||||||||||
| 70,671 | 83,279 | 22,368 | 68,645 | |||||||||||||
|
Net
fair value of derivative instruments - asset (liability)
|
$ | 163,226 | $ | 217,249 | $ | 196,121 | $ | (38,643 | ) | |||||||
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
The
following table identifies the changes in the fair value of commodity based
derivatives as reflected in the Partnership’s statements of operations for the
three-months ended March 31, June 30, September 30 and December 31 for the years
indicated:
|
Three months ended
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
Realized
gains (losses)
|
||||||||||||||||
|
Oil
|
$ | (10,885 | ) | $ | (45,232 | ) | $ | (37,585 | ) | $ | 48,660 | |||||
|
Natural
gas
|
(24,010 | ) | (237,628 | ) | 75,399 | 301,595 | ||||||||||
|
Realized
(loss) gain
|
(34,895 | ) | (282,860 | ) | 37,814 | 350,255 | ||||||||||
|
Unrealized
(loss) gain
|
(363,931 | ) | (566,693 | ) | 1,627,955 | 556,381 | ||||||||||
|
Oil
and gas price risk management gain (loss), net
|
$ | (398,826 | ) | $ | (849,553 | ) | $ | 1,665,769 | $ | 906,636 | ||||||
|
Three months ended
|
||||||||||||||||
|
March 31, 2007
|
June 30, 2007
|
September 30, 2007
|
December 31, 2007
|
|||||||||||||
|
Realized
gains (losses)
|
||||||||||||||||
|
Oil
|
$ | (1,422 | ) | $ | (1,552 | ) | $ | (449 | ) | $ | (181 | ) | ||||
|
Natural
gas
|
(6,228 | ) | 53,992 | 99,166 | 28,582 | |||||||||||
|
Realized
(loss) gain
|
(7,650 | ) | 52,440 | 98,717 | 28,401 | |||||||||||
|
Unrealized
(loss) gain
|
(141,498 | ) | 54,023 | (21,128 | ) | (234,764 | ) | |||||||||
|
Oil
and gas price risk management gain (loss), net
|
$ | (149,148 | ) | $ | 106,463 | $ | 77,589 | $ | (206,363 | ) | ||||||
Note 5 -
Capitalized Costs
Relating to Oil and Gas Activities
The
Partnership is engaged solely in oil and natural gas activities, all of which
are located in the continental United States. Drilling operations
began upon funding in July 2004 with advances made to the Managing General
Partner for all planned drilling and completion costs for the Partnership made
in December 2004. Costs capitalized for these activities are as
follows:
|
As of
|
||||||||||||||||
|
March 31, 2008
|
June 30, 2008
|
September 30, 2008
|
December 31, 2008
|
|||||||||||||
|
|
||||||||||||||||
|
Leasehold
costs
|
$ | 240,400 | $ | 240,400 | $ | 240,400 | $ | 240,400 | ||||||||
|
Development
costs
|
19,901,734 | 19,864,273 | 19,864,273 | 19,865,698 | ||||||||||||
|
Oil
and gas properties, successful efforts method, at cost
|
20,142,134 | 20,104,673 | 20,104,673 | 20,106,098 | ||||||||||||
|
Less:
Accumulated depreciation, depletion and amortization
|
(7,097,664 | ) | (7,491,786 | ) | (7,810,379 | ) | (8,156,676 | ) | ||||||||
|
Oil
and gas properties, net
|
$ | 13,044,470 | $ | 12,612,887 | $ | 12,294,294 | $ | 11,949,422 | ||||||||
|
As of
|
||||||||||||||||
|
March 31, 2007
|
June 30, 2007
|
September 30, 2007
|
December 31, 2007
|
|||||||||||||
|
Leasehold
costs
|
$ | 240,400 | $ | 240,400 | $ | 240,400 | $ | 240,400 | ||||||||
|
Development
costs
|
19,895,500 | 19,895,500 | 19,895,500 | 19,895,500 | ||||||||||||
|
Oil
and gas properties, successful efforts method, at cost
|
20,135,900 | 20,135,900 | 20,135,900 | 20,135,900 | ||||||||||||
|
Less:
Accumulated depreciation, depletion and amortization
|
(5,760,151 | ) | (6,121,019 | ) | (6,440,680 | ) | (6,758,975 | ) | ||||||||
|
Oil
and gas properties, net
|
$ | 14,375,749 | $ | 14,014,881 | $ | 13,695,220 | $ | 13,376,925 | ||||||||
Note 6 -
Commitments and
Contingencies
Colorado Royalty
Settlement. On May 29, 2007, Glen Droegemueller, individually
and as representative plaintiff on behalf of all others similarly situated,
filed a class action complaint against the Managing General Partner in the
District Court, Weld County, Colorado alleging that the Managing General Partner
underpaid royalties on natural gas produced from wells operated by the Managing
General Partner in parts of the State of Colorado (the “Droegemueller
Action”). The plaintiff sought declaratory relief and to recover an
unspecified amount of compensation for underpayment of royalties paid by us
pursuant to leases. The Managing General Partner removed the case to
Federal Court on June 28, 2007. On October 10, 2008, the court
preliminarily approved a settlement agreement between the plaintiffs and the
Managing General Partner, on behalf of itself and the Partnership.
Although the Partnership was not named as a party in the suit, the lawsuit
states that it relates to all wells operated by the Managing General Partner,
which includes a majority of the Partnership’s 16 wells in the Wattenberg
field. The portion of the settlement relating to the Partnership’s
wells for all periods through December 31, 2008 is approximately $18,000
including legal costs of approximately $1,000. This entire settlement
of $17,713 was deposited by the Managing General Partner into an escrow account
on November 3, 2008. Notice of the settlement was mailed to members
of the class action suit in the fourth quarter of 2008. The final
settlement was approved by the court on April 7, 2009. Settlement
distribution checks were mailed in July 2009. During September 2009,
all settlement costs were passed through to the Partners and any required
judicial action from the settlement of the suit was implemented in this
distribution.
PDC
2004-B LIMITED PARTNERSHIP
Notes to
Unaudited Condensed Quarterly Financial Statements
Colorado Stormwater
Permit. On December 8, 2008, the Managing General Partner
received a Notice of Violation /Cease and Desist Order (the “Notice”) from the
Colorado Department of Public Health and Environment, related to the stormwater
permit for the Garden Gulch Road. The Managing General Partner
manages this private road for Garden Gulch LLC. The Managing General
Partner is one of eight users of this road, all of which are oil and gas
companies operating in the Piceance region of Colorado. Operating
expenses, including this fine, if any, are allocated among the eight users of
the road based upon their respective usage. The Partnership has seven
wells in this region. The Notice alleges a deficient and/or
incomplete stormwater management plan, failure to implement best management
practices and failure to conduct required permit inspections. The Notice
requires corrective action and states that the recipient shall cease and desist
such alleged violations. The Notice states that a violation could result
in civil penalties up to $10,000 per day. The Managing General Partner’s
responses were submitted on February 6, 2009 and April 8, 2009. Given the
preliminary stage of this proceeding and the inherent uncertainty in
administrative actions of this nature, the Managing General Partner is unable to
predict the ultimate outcome of this administrative action at this
time.
Derivative
Contracts. The Partnership is exposed to oil and natural gas
price fluctuations on underlying sales contracts should the counterparties to
the Managing General Partner’s derivative instruments not
perform. Nonperformance is not anticipated. The Managing
General Partner has had no counterparty default losses to date.
F-43