UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


WASHINGTON,
DC 20549





FORM
10-K





T  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


£ TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934





Commission
File Number  000-52787





Rockies
Region 2006 Limited Partnership


(Exact
name of registrant as specified in its charter)





West Virginia
                  20-5149573(State
      or other jurisdiction of incorporation or organization)
                  (I.R.S. Employer Identification
      No.)





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:





Title
      of Each ClassLimited
      Partnership Interests





Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act.  Yes £  No
T





Indicate
by check mark if registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes £  No
T





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 T  No  £





Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will 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.  T





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:





Large
      accelerated filer     £
              Accelerated
      filer     £Non-accelerated
      filer     £
              Smaller
      reporting company     T





Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).  Yes£  No
T





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
March 31, 2009 the Partnership had 4,497.03 units of limited partnership
interest and no units of general partnership interest outstanding.










ROCKIES REGION 2006 LIMITED PARTNERSHIP


INDEX
TO REPORT ON FORM 10-K





PagePART
      IItem
      1
                  Business
                  1Item
      1A
                  Risk Factors
                  13Item
      1B
                  Unresolved Staff Comments
                  21Item
      2
                  Properties
                  21Item
      3
                  Legal Proceedings
                  23Item
      4
                  Submission of Matters to a Vote of Security
      Holders
                  23PART
      IIItem
      5
                  Market for Registrant’s Common Equity, Related Stockholder
      Matters and Issuer Purchases of Equity Securities
                  23Item
      6
                  Selected Financial Data
                  25Item
      7
                  Management’s Discussion and Analysis of Financial Condition and
      Results of Operations
                  25Item
      7A
                  Quantitative and Qualitative Disclosures About Market
      Risk
                  25Item
      8
                  Financial Statements and Supplementary Data
                  37Item
      9
                  Changes in and Disagreements With Accountants on Accounting and
      Financial Disclosure
                  37Item
      9A(T)
                  Controls and Procedures
                  38Item
      9B
                  Other Information
                  40PART
      IIIItem
      10
                  Directors, Executive Officers and Corporate
      Governance
                  40Item
      11
                  Executive Compensation
                  44Item
      12
                  Security Ownership of Certain Beneficial Owners and Management
      and Related Stockholder Matters
                  44Item
      13
                  Certain Relationships and Related Transactions, and Director
      Independence
                  44Item
      14
                  Principal Accountant Fees and Services
                  45PART
      IVItem
      15
                  Exhibits, Financial Statement Schedules
                  46Signatures
                  49Financial Statements
                  F-1


Index




PART
I





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 (“Exchange Act”) regarding Rockies Region 2006
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 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:





·
            changes
      in production volumes, worldwide demand, and commodity prices for oil and
      natural gas;


·
            risks
      incident to the operation of natural gas and oil
  wells;


·
            future
      production and development costs;


·
            the
      availability of sufficient pipeline and other transportation facilities to
      carry Partnership production and the impact of these facilities on
      price;


·
            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;


·
            the
      effect of natural gas and oil derivatives
  activities;


·
            availability
      and cost of capital and conditions in the capital markets;
    and


·
            losses
      possible from pending or future litigation and the costs incident
      thereto.





Further,
the Partnership urges the reader to carefully review and consider the
disclosures 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 Securities and Exchange Commission, or SEC.  Readers
are cautioned not to place undue reliance on forward-looking statements, which
speak only as of the date of this report.  The Partnership and
Managing General Partner undertake 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.








Item 1.
            Business





General





The
Partnership was organized as a limited partnership on July 20, 2006, 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 a private placement of its securities on
September 7, 2006, the Partnership was funded and commenced its business
operations. The Partnership was funded with initial contributions of $89,940,527
from 2,022 limited and additional general partners (collectively, the “Investor
Partners”) and a cash contribution of $38,912,342 from the Managing General
Partner.  After payment of syndication costs of $9,084,039 and a
one-time management fee to the Managing General Partner of $1,349,108, the
Partnership had available cash of $118,419,722 to commence Partnership
activities.  The Partnership owns natural gas and oil wells located in
Colorado and North Dakota, and from the wells, it produces and sells natural gas
and oil.


-1-
 Index


Drilling
Activities





The
Partnership commenced drilling activities immediately following funding on
September 7, 2006.  As of December 31, 2008, a total of 97 gross wells
had been drilled and the activity for the applicable periods is reflected in the
table below.  Wells drilled and not completed in 2006 became wells
drilled, fractured and producing in 2007.  There were no additional
drilling activities in 2008.  The Partnership’s 97 gross wells drilled
are located in the Rocky Mountain Region: 90 wells were drilled in Colorado and
seven were drilled in North Dakota.  See Item 2,Propertiesfor disclosure
regarding the Partnership’s wells.





2007
                  
                  
                  2006Gross
                  
                  
                  Net
                  
                  
                  Gross
                  
                  
                  NetExploratory
      WellsDrilled,
      fractured and producing
                  
                  
                  1.0
                  
                  
                  
                  0.6
                  
                  
                  
                  -
                  
                  
                  
                  -Drilled
      and not completed
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  1.0
                  
                  
                  
                  1.0Dry
      hole
                  
                  
                  5.0
                  
                  
                  
                  5.0
                  
                  
                  
                  -
                  
                  
                  
                  -Development
      wells:Drilled,
      fractured and producing
                  
                  
                  66.0
                  
                  
                  
                  65.8
                  
                  
                  
                  24.0
                  
                  
                  
                  24.0Drilled
      and not completed
                  
                  
                  -
                  
                  
                  
                  -
                  
                  
                  
                  44.0
                  
                  
                  
                  43.9Dry
      hole
                  
                  
                  1.0
                  
                  
                  
                  1.0
                  
                  
                  
                  -
                  
                  
                  
                  -Total
                  
                  
                  73.0
                  
                  
                  
                  72.4
                  
                  
                  
                  69.0
                  
                  
                  
                  68.9





A
development well is a well that is drilled close to and into the same formation
as a well which has already produced and sold oil or natural gas.  An
exploratory well is one which is drilled in an area where there has been no oil
or natural gas production, or a well which is drilled to a previously untested
or non-producing zone in an area where there are wells producing from other
formations.





The 97
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.





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.





Business
Segments





The
Partnership operates in one segment, oil and natural gas sales.





Plan of
Operations





With
regard to the Partnership’s wells drilled in Colorado, 64 developmental wells
were drilled to the Codell formation in the Wattenberg Field (one of which was
determined to be a developmental dry hole) while three exploratory wells were
drilled and were evaluated to be exploratory dry holes. The remaining 23
Colorado wells were developmental wells drilled in the Grand Valley Field which
were successfully completed and in production.  In North Dakota, the
Partnership drilled seven wells in the western portion of the Williston Basin:
four developmental wells were successfully completed and in production while of
the three exploratory wells drilled, one was successfully completed and turned
into line and two were determined to be exploratory dry holes.


-2-
 Index


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 in the Denver-Julesburg (DJ) Basin.  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 for most of the Partnership’s wells
is the Codell which produces a combination of natural gas and oil.





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 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
typical well production profile for wells in both the Wattenberg and Grand
Valley fields 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 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.





PDC plans
to recomplete most 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.  A recompletion consists of a second fracture
treatment in the same formation originally fractured in the initial
completion.  PDC and other producers have found that the recompletions
generally increase the production rate and recoverable reserves of the
wells.  On average, the production resulting from PDC's Codell
recompletions has been above the modeled economics; however, all recompletions
have not and may not be successful.  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
its proportionate share of costs based on the operating costs sharing ratios of
the Partnership.  The Partnership may borrow the funds necessary to
pay for the recompletions, and payment for those borrowings will be made from
the Partnership production proceeds. Any such borrowings will be non-recourse to
the Investor Partners in the Partnership.





Partnership
wells in North Dakota are located in the western portion of the Williston Basin
in northwestern North Dakota.  Successful wells drilled in this area
are expected to produce oil and natural gas, with some associated produced
water.  Wells drilled in this area targeted hydrocarbon reserves in
the Nesson and/or Bakken interval.  Development encompassed horizontal
drilling within the target zone(s) with single or multi-lateral horizontal well
bores of 4,000 feet or more.  True vertical well depths may vary from
5,000 to 8,000 feet with total measured well depths, including the lateral well
bore(s) ranging from approximately 10,000 to 20,000 feet.





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 Limited Partnership Agreement (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.  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 and equipping of wells and the sale of the Partnership’s oil
and natural gas production from wells.  PDC is the operator of all of
the wells in which the Partnership owns an interest.


-3-
 Index


PDC, in
some cases, provides equipment and supplies, and performs 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.  All of the
Partnership's wells are in the vicinity of transmission pipelines and gathering
systems.  PDC believes there are sufficient transmission pipelines and
gathering systems for the Partnership's natural gas production, subject to some
seasonal curtailment and occasional limitations because of repairs, improvements
or as a result of priority transportation agreements with other gas
transporters.  Seasonal curtailment typically occurs during July and
August as a result of high temperatures which reduce compressor
capacity.  This reduction in production typically amounts to less than
five percent of normal monthly production without an effect on
pricing.  The cost, timing and availability of gathering pipeline
connections and service varies from area to area, well to well, and over
time.  In selecting prospects for the Partnership, PDC included in its
evaluation the anticipated cost, timing and expected reliability of gathering
connections and capacity. 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
can lead to lower natural gas prices relative to other areas as the producers
compete for the available markets by reducing prices.  It can also
lead to curtailments of production and periods when wells are shut-in due to
lack of market.  The Partnership experienced shut in wells in October
2007 and third and fourth quarter, 2008.  While the Partnership’s
ability to market its natural gas has been only infrequently limited or delayed,
if transportation space is restricted or unavailable, Partnership cash flows
could be adversely affected.





Sale of Production.  The Partnership
sells the oil and natural gas produced from its wells on a competitive basis at
the best available terms and prices generally, under contracts with indexed
monthly pricing provisions.  PDC does not make any commitment of
future production that does not primarily 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 contracts with a term
of a number of years and that may require the dedication of the natural gas from
a well for a period ranging up to the life of the well.





The
Partnership sells gas at negotiated prices based upon a number of factors,
including the quality of the gas, well pressure, estimated reserves, prevailing
supply conditions and any applicable price regulations promulgated by the
Federal Energy Regulatory Commission, or FERC.  The Partnership sells
oil produced by it 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 natural gas from its 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.
For instance, the Partnership experienced an approximate 10% to 15% 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.





PriceRisk
Management.  Price volatility is a very significant and
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 maintains a conservative financial
approach and proactively employs strategies to reduce the effects of commodity
price volatility 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 and New York Mercantile Exchange, or NYMEX, based
contracts for Colorado oil production.  The contracts provide price
protection for committed and anticipated oil and natural gas sales, generally
forecasted to occur within the next two to three-year period, but in no cases
longer than five years beyond the derivative transaction date.  The
Partnership's policies prohibit the use of oil and natural gas futures, 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, they do not qualify for use of hedge
accounting 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.  See Note 2, Summary of Significant Accounting
Policies−Derivative Financial Instruments, to the Partnership’s
accompanying financial statements included in this report.


-4-
 Index


The
Partnership is subject to 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.  In addition, 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 December 31,
2008, the Partnership has oil and natural gas derivatives in place covering 55%
of its expected oil production and 75% of its expected natural gas production
for 2009.





The
Partnership uses 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
carried 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 gain (loss), 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.  For “swap” instruments, PDC as Managing General Partner,
receives a fixed price for the hedged commodity and pays a floating market price
to the counterparty. The fixed-price payment and the floating-price payment are
netted, resulting in a net amount due to or from the counterparty. “Collars”
contain a fixed floor price (put) and ceiling price (call). If the market price
exceeds the ceiling strike price or falls below the fixed floor price, PDC, as
Managing General Partner, receives the fixed floor price and pays the market
price. If the market price is between the ceiling and floor price, no payments
are due either party.  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 revenue and cash
flows compared to the level the Partnership might experience if no derivative
instruments were in place.





The
Partnership participates in all derivative transactions entered into by the
Managing General Partner in a given area.  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 each of
the sponsored drilling partnerships changed.  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.  This allocation methodology is considered reasonable by
management of the Managing General Partner.  The Partnership believes
that in this rapidly changing price environment, derivative positions are
desirable to obtain more predictable results and to reduce the impact of
possible severe price declines during this crucial state of flush production
from the Partnership wells.





Drilling and Operating
Agreement.  The Partnership
has entered into a Drilling and Operating Agreement with PDC.  The
Drilling and Operating 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.  The operator has no 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 drilling and operating agreement, PDC may subcontract responsibilities 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 received 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.


-5-
 Index


The
operator provides all necessary labor, vehicles, supervision, management,
accounting, and overhead services for normal production operations, and deducts
from Partnership revenues a 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 Drilling and Operating 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.





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.  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.  If pipelines owned by PDC are used in the delivery of natural
gas to market, PDC charges a gathering fee not to exceed that which would be
charged by a non-affiliated third party for a similar service.





The
Drilling and Operating Agreement continues in force as long as any well or wells
produce, or are capable of 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 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 being conducted with regard to each of the ninety-one producing
wells.





The
Partnership sells the produced 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 be dedicated to particular markets at the time the
Partnership acquired those leases, or subsequent to, as part of the natural gas
marketing arrangements.





The
majority of the Partnership’s wells in the Wattenberg Field in Colorado and the
Partnership’s wells in North Dakota produce oil in addition to natural
gas.  The Managing General Partner is currently able to sell all the
oil and natural gas 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 swaps, in order to offset some or
all of the price variability for particular periods of time, generally for two
to three years, but in no cases longer than five years.  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 pipelines may impact the Partnership's results.  In
addition, both sales volumes and prices tend to be affected by demand factors
with a significant 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.


-6-
 Index


The above
items of expenditure involve amounts payable solely out of and expenses incurred
solely by reason of production operations.  Although the Partnership
is permitted to borrow funds for its operations, 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 sufficient to render full payment.





Interests of
Partiesin
Production Revenues





PDC, the
Investor Partners, and unaffiliated third parties (including landowners) share
revenues from production of natural gas and oil from wells in which the
Partnership has an interest.  The following chart illustrates the
interest of gross revenues derived from the wells.  For the purpose of
this chart, "gross revenue" is defined as the "wellhead gas and oil revenue"
paid by the purchasers.  Landowner and other royalties payable to
unaffiliated third parties may vary, generally between 12.5% to 25% or more;
however, the average of the royalty interests for all prospects or wells of the
Partnership may not exceed 25%.





Illustration
      of Partnership Revenue SharingEntity
      or Interest Owners
                                Partnership
      Interests
                                Gross
      Revenue Interests (Partnership Revenues and Third Party
      Royalties)If
      121⁄2% Royalty:
                                If
      25% Royalty:PDC,
      the Managing General Partner
                                37%
                                32.375%
                                27.75%Investor
      Partners
                                63%
                                55.125%
                                47.25%Landowners
      and Over-riding Royalty Owners
                                N/A
                                12.5%
                                25.00%Totals
                                100%
                                100.00%
                                100.00%


-7-
 Index


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
      EndedDecember
      31, 2008
                    
                    
                    December
      31, 2007ProductionOil
      (Bbls)
                    
                    
                    149,441
                    
                    
                    
                    297,477Natural
      gas (Mcf)
                    
                    
                    2,531,853
                    
                    
                    
                    3,136,904Natural
      gas equivalent (Mcfe)
                    
                    
                    3,428,499
                    
                    
                    
                    4,921,766Oil
      and Gas SalesOil
      sales
                    
                    $
                    13,024,803
                    
                    
                    $
                    18,332,887Gas
      sales
                    
                    
                    16,934,444
                    
                    
                    
                    13,609,342Total
      oil and gas sales
                    
                    $
                    29,959,247
                    
                    
                    $
                    31,942,229Realized
      Gain (Loss) on Derivatives, netOil
      derivatives - realized loss
                    
                    $
                    (432,928
                    )
                    
                    $
                    -Natural
      gas derivatives - realized gain
                    
                    
                    1,013,121
                    
                    
                    
                    207,442Total
      realized gain on derivatives, net
                    
                    $
                    580,193
                    
                    
                    $
                    207,442Average
      Sales PriceOil
      (per Bbl)
                    
                    $
                    87.16
                    
                    
                    $
                    61.63Natural
      gas (per Mcf)
                    
                    
                    6.69
                    
                    
                    
                    4.34Natural
      gas equivalent (per Mcfe)
                    
                    
                    8.74
                    
                    
                    
                    6.49Average
      Sales Price (including realized gain (loss)on derivatives)Oil
      (per Bbl)
                    
                    
                    84.26
                    
                    
                    
                    61.63Natural
      gas (per Mcf)
                    
                    
                    7.09
                    
                    
                    
                    4.40Natural
      gas equivalent (per Mcfe)
                    
                    
                    8.91
                    
                    
                    
                    6.53Average
      Production Cost (Lifting Cost) per Mcfe
                    
                    $
                    1.50
                    
                    
                    $
                    1.13





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 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





Production
as shown in the table is net and 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.  A ratio of energy content of natural gas and oil (six Mcf of
natural gas equals one barrel of oil) was used to obtain a conversion factor to
convert oil production into equivalent Mcf of natural gas.





The
Partnership utilizes commodity based derivative instruments to manage a portion
of its exposure to 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 Conditions and Results of Operations - Production and Operating
Costs.


-8-
 Index


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 engineers'
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.  Reserves
cannot be measured exactly, because reserve estimates involve subjective
judgment.  The estimates must be reviewed periodically and adjusted to
reflect additional information gained from reservoir performance, 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
the Partnership owns.





December
      31, 2008Oil
      (MBbl)
                          
                          
                          Gas
      (MMcf)
                          
                          
                          Total (MMcfe)Proved
      developed
                          
                          
                          596
                          
                          
                          
                          16,820
                          
                          
                          
                          20,396Proved
      undeveloped
                          
                          
                          576
                          
                          
                          
                          3,053
                          
                          
                          
                          6,509Total
      Proved
                          
                          
                          1,172
                          
                          
                          
                          19,873
                          
                          
                          
                          26,905Proved
                          
                          
                          Proved
                          
                          
                          TotalDeveloped
                          
                          
                          Undeveloped
                          
                          
                          ProvedEstimated
      future net cash flows (in
      thousands)
                          
                          $
                          57,558
                          
                          
                          $
                          17,853
                          
                          
                          $
                          75,411Standardized
      measure(in
      thousands)
                          
                          
                          35,485
                          
                          
                          
                          5,184
                          
                          
                          
                          40,669





Estimated
future net cash flow represents the estimated future gross revenue 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 $37.28 per barrel of oil and $4.71 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 SFAS No. 69, 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, carries well pollution, public liability and worker’s
compensation insurance for its own benefit as well as the benefit of the
Partnership, but that insurance may not be sufficient to cover all
liabilities.  Each unit held by the general partners, excluding the
Managing General Partner, represents an open-ended security for unforeseen
events such as blowouts, lost circulation, and stuck drill pipe, which may
result in unanticipated additional liability materially in excess of the per
unit subscription amount.


-9-
 Index


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
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 their activities.  In the event of a loss, the
insurance policies of the particular subcontractor at risk would 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 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. 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 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 has 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 affected 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 different regions.


-10-
 Index


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.





Various
parts of the fields in which the Partnership’s wells are located are crossed by
pipelines belonging to Colorado Interstate Gas, Encana, DCP Midstream LP (“DCP”,
formerly Duke Energy), 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 Colorado
Interstate Gas, Williams or other pipelines.  As a result of FERC
regulations that require interstate gas pipelines to separate their merchant
activities from their transportation activities and require them to release
available capacity on both a short and a long-term basis, local distribution
companies must take an increasingly active role in acquiring their own natural
gas supplies.  Consequently, pipelines and local distribution
companies 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 added to
competition in the natural gas marketplace.





Natural Gas and Oil
Pricing





PDC sells
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 primarily 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 is subject to changes in market prices on a national level, as well
as changes in the market 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 crude oil from Partnership wells to Teppco Crude
Oil, LP (“Teppco”) and Shell Trading (US) Company
(“Shell”).  Generally, 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. Additionally, the cost of trucking or
transporting the oil to market affects the price the Partnership ultimately
receives for the oil.





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.


-11-
 Index


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 us 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 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.


-12-
 Index


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, that 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 0001376912.  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.  In particular, consider the risks related to (1) 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 and (2)
the effect of constraints on the availability of credit for financing well
recompletion activities.  Also consider the interplay between these
two risks: the decline in oil and gas prices can lead to a reduction in the
Managing General Partner’s credit line borrowing base, which it may utilize on
behalf of the Partnership or other partnerships for which PDC serves as Managing
General Partner, to fund Partnership well recompletion
activities.  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, further eroding the Managing
General Partner’s borrowing base, by its share of such oil and natural gas
reserve reductions, thus increasing the likelihood for borrowing cost increases
or loss of borrowing fund availability, for Partnership
activities.  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 to 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 andnaturalgas and the prices of oil
andnaturalgas 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.  Furthermore, as a result
of these disruptions in the financial markets, it is possible that in future
years the Partnership would not be able to borrow sufficient funds to recomplete
most 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.  Any of the above factors could adversely affect the
Partnership’s operating results.  For more information regarding the
Wattenberg Field recompletion plan, see Item 1 Business, Plan of
Operation.


-13-
 Index


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, 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 of the prior 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 or borrow funds 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 either retain Partnership
revenues or borrow the funds from the Managing General Partner or other third
parties if borrowed funding is available, that is necessary for these
purposes.  Retaining Partnership revenues and/or the repayment of
borrowed funds 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 held 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 or to repay financial obligations of the Partnership for borrowed funds
plus interest.  If future development of the Partnership's wells is
not commercially successful, whether using funds retained from production
revenues or borrowed funding if available, these operations could result in a
reduction of cash distributions to the Investor Partners of the
Partnership.





The inability of one or more
of the Partnership’s customersor derivative
counterpartiesto 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
affect the performance and profitability of the Partnership in both the short
and long term.  In the current high price environment, most oil
and natural gas companies have 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 gaswillreduce 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 completions, and it is uncertain low long such low pricing shall
persist.


-14-
 Index


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 September 4, 2007.  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:





·
            PDC
      might sponsor additional drilling programs 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.





·
            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.





·
            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
      service, PDC will benefit financially from this
    relationship.


-15-
 Index


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 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.


-16-
 Index


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 plans to recomplete various of
its Wattenberg Wells in approximately five years, 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, results of operations, and the availability
of capital resources.  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, results of operations and the availability of
capital resources. 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 production based
upon prices at which the Managing General Partner reasonably estimates such
products may be sold.  The Partnership recorded impairments of
$13,414,497 since its operations commenced in September 2006.  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.


-17-
 Index


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 Investors
Partners.





Two Colorado lawsuits
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, a
complaint was filed against PDC in Weld County, Colorado.  The
complaint represented a class action against PDC seeking compensation for
alleged underpayment of royalties on leases in Colorado, resulting from the
alleged miscalculation of costs to produce marketable gas.  The case
was moved to Federal Court in June 2007.  A second similar Colorado
class action suit was filed against PDC on December 3, 2007.  On
January 28, 2008, the Court granted a motion to consolidate the two cases, and
on February 29, 2008, the Court approved a 90 day stay in the proceedings while
the parties pursued mediation of the matter.





The court
approved a stay in proceedings until September 22, 2008 while the parties
pursued mediation of the matter.  Based on the mediation held on May
28, 2008, and subsequent negotiations, $39,100 was accrued by the Partnership
for this litigation for the year ended December 31, 2007.  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 64 wells in the Wattenberg field subject to the
settlement.  On October 10, 2008, the court issued preliminary
approval of the settlement agreement. The portion of the proposed settlement
related to the Partnership’s wells for all periods through December 31, 2008 is
$146,023.  During 2008, an additional amount of $106,023 plus legal
costs of $12,260 were recorded to fully accrue for the settlement through
December 31, 2008.  In November 2008, the Managing General Partner
paid into an escrow account, on behalf of the Partnership, amounts due under the
settlement.  These amounts will be deducted from future Partnership
distributions.  Notice of the settlement was mailed to members of the
class action suit in fourth quarter 2008 and the final settlement approval
hearing is expected on April 7, 2009.





Special Risks of an
Investment in the Partnership





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.  The offer and sale of units have not
been, and will not in the future be, registered under the Securities Act or
under any state securities laws.  Each purchaser of units has been
required to represent that such investor has purchased the units for his or her
own account for investment purposes and not with a view to resale or
distribution.  No transfer of a unit may be made unless the transferee
is an "accredited investor" and such transfer is registered under the Securities
Act and applicable state securities laws, or an exemption there from is
available.  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.


-18-
 Index


Dry hole or non-commercially
viable drilling prospect costs associated with the Partnership's drilling have
resulted in reduced distributions to the Investor Partners.To
date, the Partnership has drilled a total of 97 wells.  Of these
wells, six have been determined to be commercially unproductive and therefore
declared to be dry holes.  As dry holes result in no production of oil
and natural gas, the occurrence of dry holes causes the revenues and
distributions to be less than if the wells drilled had been commercially
productive.  From inception through December 31, 2008, the Partnership
has recorded $8,218,179 in exploratory dry hole costs.





The
Partnership assesses impairment of capitalized costs of proved oil and natural
gas properties 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 management reasonably estimates such production to be
sold.  From inception through December 31, 2008, the Partnership's
impairment charges totaled $13,414,497.  Unlike dry holes, impaired
properties may still produce oil and natural gas which can be sold, however, the
impaired properties may not generate enough production for the Partnership to
recoup the amounts invested in the properties.





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 September 4,
2007.  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. 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.


-19-
 Index


A substantial part of our
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 and cash
flow.





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 current
Partnership financial statements and those of other partnerships sponsored by
the Managing General Partner 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 prior period financial
statements.  As a result, on October 17, 2005, PDC’s Board of
Directors, Audit Committee and management concluded that 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
October 2005, PDC has become compliant with its corporate Exchange Act filing
and reporting obligations. Additionally, Rockies Region 2007 Limited Partnership
and Rockies Region 2006 Limited Partnership have completed all required SEC
filings through September 30, 2008; PDC 2005-A Limited Partnership and PDC
2005-B Limited Partnership have filed financial statements through December 31,
2007, however, these latter two partnerships are still delinquent with respect
to their 2008 quarterly filing requirements. These two partnerships are
currently in the process of preparing their 2008 10-K filings which will include
unaudited quarterly condensed financial statements for 2008. On March 31, 2009,
these two partnerships will become delinquent with respect to their 2008 10-K
filings if not filed before such date. PDC 2004-A Limited Partnership has filed
financial statements through December 31, 2005 but is delinquent on all
quarterly and annual filing requirements from March 31, 2006 through September
30, 2008. Rockies Region Private Limited Partnership has filed financial
statements through March 31, 2006, but is delinquent on all quarterly and annual
filings requirements from June 30, 2006 through September 30, 2008. On March 31,
2009, these two partnerships will become delinquent with respect to their 2008
10-K filings. 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.




-20-
 Index


"A material weaknesses"
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.








Item 1B.
            Unresolved
      Staff Comments





None








Item 2.
            Properties





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 97
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 -
Plan of Operations for additional information on the Partnership’s
properties.





The
Partnership commenced drilling activities immediately following funding on
September 7, 2006.  The number of wells owned by the Partnership at
December 31, for each of the three years described, is presented in the
following table.





2008
                
                
                2007
                
                
                2006Gross
                
                
                Net
                
                
                Gross
                
                
                Net
                
                
                Gross
                
                
                NetExploratory
      WellsDrilled,
      fractured and producing
                
                
                1.0
                
                
                
                0.6
                
                
                
                1.0
                
                
                
                0.6
                
                
                
                -
                
                
                
                -Drilled
      and not completed
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                1.0
                
                
                
                1.0Dry
      hole
                
                
                3.0
                
                
                
                3.0
                
                
                
                5.0
                
                
                
                5.0
                
                
                
                -
                
                
                
                -Development
      wells:Drilled,
      fractured and producing
                
                
                90.0
                
                
                
                89.8
                
                
                
                90.0
                
                
                
                89.8
                
                
                
                24.0
                
                
                
                24.0Drilled
      and not completed
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                -
                
                
                
                44.0
                
                
                
                43.9Dry
      hole
                
                
                1.0
                
                
                
                1.0
                
                
                
                1.0
                
                
                
                1.0
                
                
                
                -
                
                
                
                -Total
                
                
                95.0
                
                
                
                94.4
                
                
                
                97.0
                
                
                
                96.4
                
                
                
                69.0
                
                
                
                68.9


-21-
 Index




The 97
wells at December 31, 2007, in the table above are the only wells to be drilled
by the Partnership since all of the funds raised in the Partnership offering
have been utilized.  Two exploratory wells determined to be a
commercially nonproductive dry holes, were sold to an unaffiliated third-party
in 2008.  Productive wells consist of producing wells and wells
capable of producing oil and natural gas in commercial
quantities.  Gross wells refer to the number of wells in which the
Partnership has an interest.  Net wells refer to gross wells
multiplied by the percentage working interest owned by the
Partnership.





The
Partnership drilled 90 wells in Colorado and seven in North
Dakota.  Of the wells in Colorado, 86 were development wells which are
currently producing, one was a developmental dry hole and three exploratory
wells were all evaluated to be dry holes. Two of these exploratory Colorado dry
holes were sold in 2008.  In North Dakota, Partnership wells included
four developmental wells which are currently producing, one exploratory well
which is currently producing and two exploratory wells which were evaluated as
dry holes.  The details of these prospect areas are further outlined
below.





Colorado.  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 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 and water.  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.





North
Dakota.  Partnership wells are located in the western portion
of the Williston Basin in northwestern North Dakota.  Successful wells
drilled in this area are expected to produce oil and natural gas, with some
associated produced water.  Wells drilled in this area target
hydrocarbon reserves in the Nesson and/or Bakken
interval.  Development encompassed horizontal drilling within the
target zone(s) with single or multi-lateral horizontal well bores of 4,000 feet
or more.  True vertical well depths may vary from 5,000 to 8,000 feet
with total measured well depths, including the lateral well bore(s) ranging from
approximately 10,000 to 20,000 feet.





Production





Production
commenced during the fourth quarter of 2006, peaked during the quarter ended
September 30, 2007 and has continued to decrease as anticipated.





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
report.  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 or for additional information regarding the Partnership’s
reserves.


-22-
 Index


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 is conducted at the time the undeveloped properties are
acquired.  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 any of these burdens 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
February 28, 2009, the Partnership had 2,029 Investor Partners holding 4,497.03
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 Managing General Partner.  As of February
28, 2009, the Managing General Partner has repurchased 3.5 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.  The offer and sale of the Investor Partners' interests
("units") have not been registered under the Securities Act or under any state
securities laws.  Each purchaser of units was required to represent
that such individual investor partner was purchasing the units for his or her
own account for investment and not with a view to distribution.  No
transfer of a unit may be made unless the transferee is an "accredited investor"
and such transfer is registered under the Securities Act and applicable state
securities laws, or an exemption there from is available.  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.


-23-
 Index


Cash Distribution Policy.  PDC plans to
make distributions of Partnership cash on a monthly basis, but no less often
than quarterly, if funds are available for distribution.  PDC will
make cash distributions of 63% to the Investor Partners, adjusted for any units
purchased by the Managing General Partner, and 37% to the Managing General
Partner throughout the term of the Partnership.





PDC
cannot presently predict amounts of cash distributions, if any, from the
Partnership.  However, PDC expressly conditions any distribution upon
its 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 debt instruments or
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 $26,226,112
and $20,645,528 for the years ended December 31, 2008 and 2007,
respectively.





In
general, the volume of production from producing properties declines with the
passage of time.  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 prospects.  If
the Partnership decides to develop its wells further, the funds necessary for
that development would come from the Partnership's revenues and/or from borrowed
funds.  As a result, there may be a decrease in the funds available
for distribution, and the distributions to the Investor Partners may
decrease.





In
general, PDC divides cash distributions 63% to the Investor Partners and 37% to
PDC throughout the term of the Partnership.  Cash is distributed to
the Investor Partners and PDC as a return on capital, in the same proportion as
their interest in the net income of the Partnership.  However, no
individual investor partner will receive distributions to the extent the
distributions would create or increase a deficit in that investor partner's
capital account.





PDC, as
Managing General Partner, intends to develop the Partnership's interests in its
properties only with the proceeds of subscriptions and PDC's capital
contributions.  However, these funds may not be sufficient to fund all
future well costs, and it may be necessary for the Partnership to retain
Partnership revenues for the payment of these costs, or for PDC to advance the
necessary funds to the Partnership or for the Partnership to borrow necessary
funds.  It is likely that the Partnership's Wattenberg Field, Colorado
wells will benefit from recompletion services, generally in five years or longer
following initial drilling of those wells.  Recompletion is the
process of going into an existing zone which is already producing for a
“refrac,” or refracture operation to go into a new zone at a different depth,
all with the objective of increasing the production of oil or natural
gas.  If PDC retains Partnership revenues for the payment of these
recompletion or “refrac” costs, the amount of Partnership funds available for
distribution to the Investor Partners of the Partnership will decrease
correspondingly.  Development work will not include the drilling of
any new wells beyond the initial wells that have been drilled.  PDC
may retain payment for the recompletion or “refrac” work from Partnership
proceeds, by preparing an Authority for Expenditure, or AFE, estimate for the
Partnership in either of the two methods:





·
            PDC
      will complete the development work and will bill the Partnership for the
      work performed and will be reimbursed from future production;
      or


-24-
 Index


·
            The
      Partnership will retain revenues from operations until it has accumulated
      or borrowed sufficient funds to pay for the development work, at which
      time PDC will commence the work, and PDC will be reimbursed as the work
      progresses from retained revenues.





Should
the Partnership’s revenues be retained for the payment of recompletion or
“refrac” costs, the determination of which option to use will be at PDC's
discretion, based on the amount of the anticipated expenditure and the urgency
of the necessary work.





The
Agreement also permits the Partnership to borrow funds on behalf of the
Partnership for Partnership activities. The Partnership may borrow needed funds,
or receive advances, from the Managing General Partner or affiliates of the
Managing General Partner or from unaffiliated persons.  On loans or
advances made available to the Partnership by the Managing General Partner or
affiliates of the Managing General Partner, the Managing General Partner or
affiliate may not receive interest in excess of its interest costs, nor may the
Managing General Partner or affiliate receive interest in excess of the amounts
which would be charged the Partnership (without reference to the Managing
General Partner's financial abilities or guarantees) by unrelated banks on
comparable loans for the same purpose.  The Managing General Partner
anticipates that borrowed funds will be utilized to finance Codell recompletion
activities (see Item 1, Business).  As the
Partnership will have to pay interest on borrowed funds, the amount of
Partnership funds available for distribution to the partners of the Partnership
will be reduced accordingly.





Individual
investor partners who are independent producers are entitled to claim a
percentage depletion deduction against their oil and natural gas
income.  The percentage depletion rate for oil and gas properties is
generally 15% of the gross income generated by the property.





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 May
2007. If requested by individual investor partners, the Managing General Partner
is 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
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.  During
2008, the Managing General Partner made first quarter unit repurchases in
February 2008 of 2.5 units at an average price of $10,000 per unit and second
quarter unit repurchases in April 2008 of 1.0 unit at an average price of
$15,000 per unit.  There were no additional units repurchased during
the remainder of 2008.





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 financial statements included in this
report.  Further, the Partnership encourages you to revisit Special Note Regarding
Forward-Looking Statements on page 1 of this report.





Overview





The
Partnership was funded on September 7, 2006 with initial contributions of
$89,940,527 from the Investor Partners and a cash contribution of $38,912,342
from the Managing General Partner.  After payment of syndication costs
of $9,084,039 and a one-time management fee to PDC of $1,349,108, the
Partnership had available cash of $118,419,722 to commence Partnership oil and
natural gas well drilling activities.


-25-
 Index


The
Partnership began exploration and development activities immediately after
funding.  The full amount of the funding was paid to PDC to begin the
drilling of oil and natural gas wells, on behalf of the Partnership under the
Drilling and Operating Agreement.  The payment to PDC was made as an
advance of exploration and development costs for oil and natural gas
properties.  In September 2006, PDC commenced drilling on behalf of
the Partnership.  As of December 31, 2008, a total of 97 wells have
been drilled, predominantly in Colorado.  Of the 97 wells drilled, 91
are producing and six, five exploratory wells and the other one developmental,
were dry holes.  These 97 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 2006 as wells were connected to
pipelines.  The Partnership’s wells will produce until they are
depleted or until they are uneconomical to produce; however, it is 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.  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 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 dropped almost by half.  The Managing General Partner’s
reaction to these events is one of caution.  While the Partnership
certainly 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 impacts while capitalizing on
the positive impacts.  The Partnership’s derivative position
eased the impact of the fall in oil and natural gas prices.  The
Partnership exited 2008 with $0.5 million in net realized derivative gains, $2.1
million in the fourth quarter alone.  Further, the Partnership
estimates the net fair value of its derivative positions as of December 31,
2008, to be $7.5 million.





The
decline in prices during the fourth quarter of 2008 has resulted in $8.6 million
in unrealized gains on derivatives for the year ended December 31,
2008.  The $8.6 million in unrealized gains for the year is the fair
value of the derivative positions as of December 31, 2008, less the related
unrealized amounts recorded in prior periods.  An unrealized gain is a
non-cash item and there will be further gains or losses as prices decrease or
increase until the positions mature or are closed.  While 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 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,
                        
                        
                        February
      13,Commodity
                        
                        Index
                        
                        2007
                        
                        
                        2008
                        
                        
                        2008
                        
                        
                        2009Natural
      gas:NYMEX
                        
                        $
                        8.12
                        
                        
                        $
                        12.52
                        
                        
                        $
                        6.62
                        
                        
                        $
                        5.87CIG
                        
                        
                        6.78
                        
                        
                        
                        8.86
                        
                        
                        
                        4.49
                        
                        
                        
                        4.13Oil:
                        
                        NYMEX
                        
                        
                        90.79
                        
                        
                        
                        140.15
                        
                        
                        
                        57.49
                        
                        
                        
                        53.07





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 are
expected to continue.


-26-
 Index


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, average lifting cost, other operating income and expenses for the
years ended December 31, 2008 and 2007.





Years
      Ended
                        
                        
                        Percent
      Change2008
                        
                        
                        2007
                        
                        
                        2008
      to 2007Number
      of producing wells (end of period)
                        
                        
                        91
                        
                        
                        
                        91Production:  (1)Oil
      (Bbl)
                        
                        
                        149,441
                        
                        
                        
                        297,477
                        
                        
                        
                        -50
                        %Natural
      gas (Mcf)
                        
                        
                        2,531,853
                        
                        
                        
                        3,136,904
                        
                        
                        
                        -19
                        %Natural
      gas equivalents (Mcfe)  (2)
                        
                        
                        3,428,499
                        
                        
                        
                        4,921,766
                        
                        
                        
                        -30
                        %Average
      Selling PriceOil
      (per Bbl)  (3)
                        
                        $
                        87.16
                        
                        
                        $
                        61.63
                        
                        
                        
                        41
                        %Natural
      gas (per Mcf)  (3)
                        
                        $
                        6.69
                        
                        
                        $
                        4.34
                        
                        
                        
                        54
                        %Natural
      gas equivalents (per Mcfe)  (3)
                        
                        $
                        8.74
                        
                        
                        $
                        6.49
                        
                        
                        
                        35
                        %Average
      Selling Price (including realized gain (loss), net on
      derivatives)Oil
      (per Bbl)
                        
                        $
                        84.26
                        
                        
                        $
                        61.63
                        
                        
                        
                        37
                        %Natural
      gas (per Mcf)
                        
                        $
                        7.09
                        
                        
                        $
                        4.40
                        
                        
                        
                        61
                        %Natural
      gas equivalents (per Mcfe)
                        
                        $
                        8.91
                        
                        
                        $
                        6.53
                        
                        
                        
                        36
                        %Average
      cost per McfeProduction
      and operating costs  (4)
                        
                        $
                        1.50
                        
                        
                        $
                        1.13
                        
                        
                        
                        33
                        %Depreciation,
      depletion and amortization
                        
                        $
                        3.35
                        
                        
                        $
                        3.14
                        
                        
                        
                        7
                        %Revenues:Oil
      and gas sales
                        
                        $
                        29,959,247
                        
                        
                        $
                        31,942,229
                        
                        
                        
                        -6
                        %Oil
      and gas price risk management, gain (loss), net
                        
                        
                        9,141,981
                        
                        
                        
                        (1,145,968
                        )
                        
                        
                        *Total
      revenues
                        
                        $
                        39,101,228
                        
                        
                        $
                        30,796,261
                        
                        
                        
                        27
                        %Realized
      Gain (Loss) on Derivatives, netOil
      derivatives - realized loss
                        
                        $
                        (432,928
                        )
                        
                        $
                        -
                        
                        
                        
                        *Natural
      gas derivatives - realized gain
                        
                        
                        1,013,121
                        
                        
                        
                        207,442
                        
                        
                        
                        *Total
      realized gain on derivatives, net
                        
                        $
                        580,193
                        
                        
                        $
                        207,442
                        
                        
                        
                        180
                        %Operating
      costs and expenses:Production
      and operating costs
                        
                        $
                        5,135,146
                        
                        
                        $
                        5,557,327
                        
                        
                        
                        -8
                        %Direct
      costs - general and administrative
                        
                        
                        673,877
                        
                        
                        
                        596,183
                        
                        
                        
                        13
                        %Depreciation,
      depletion and amortization
                        
                        
                        11,496,628
                        
                        
                        
                        15,476,390
                        
                        
                        
                        -26
                        %Exploratory
      dry hole cost
                        
                        
                        85,236
                        
                        
                        
                        8,132,943
                        
                        
                        
                        -99
                        %Loss
      on impairment of oil and gas properties
                        
                        
                        3,839,197
                        
                        
                        
                        2,445,617
                        
                        
                        
                        57
                        %Accretion
      of asset retirement obligations
                        
                        
                        38,362
                        
                        
                        
                        36,852
                        
                        
                        
                        4
                        %Total
      operating costs and expenses
                        
                        $
                        21,268,446
                        
                        
                        $
                        32,245,312
                        
                        
                        
                        -34
                        %Income
      (loss) from operations
                        
                        $
                        17,832,782
                        
                        
                        $
                        (1,449,051
                        )
                        
                        
                        *Gain
      on sale of oil and gas properties
                        
                        $
                        120,000
                        
                        
                        $
                        -
                        
                        
                        
                        *
                        %Interest
      expense
                        
                        $
                        -
                        
                        
                        $
                        (7,543
                        )
                        
                        
                        *
                        %Interest
      income
                        
                        $
                        85,460
                        
                        
                        $
                        173,679
                        
                        
                        
                        -51
                        %Net
      income (loss)
                        
                        $
                        18,038,242
                        
                        
                        $
                        (1,282,915
                        )
                        
                        
                        *Cash
      distributions
                        
                        $
                        26,226,112
                        
                        
                        $
                        20,645,528
                        
                        
                        
                        27
                        %





*Percentage
change not meaningful or equal to or greater than 250% or not
calculable.


Amounts
may not calculate due to rounding


_______________


1.
            Production
      is net and determined by multiplying the gross production volume of
      properties in which we have an interest by the percentage of the leasehold
      or other property interest we own.


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.


-27-
 Index


3.
            The
      Partnership utilizes commodity based derivative instruments to manage a
      portion of our exposure to price volatility of our natural gas and oil
      sales.  This amount excludes realized and unrealized gains and
      losses on commodity based derivative
  instruments.


4.
            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 gas
equivalents





Oil and Natural Gas Sales
Activity





The 6%
decrease in total sales in 2008 as compared to 2007 was due to decreased total
production volumes, in Mcfe or energy equivalency basis, of 30% partially offset
by an increase in average sales price per Mcfe, of 35%.





Decreased
volumes contributed to a reduction of $9.7 million while commodity price
increases amounted to $7.7 million, resulting in a $2.0 million decrease in oil
and natural gas sales in 2008 as compared to 2007.  This change in
production volumes is consistent with the historically declining production
curves for wells drilled in the Wattenberg and Piceance fields. Additionally,
the Partnership experienced a 10% to 15% curtailment of producing volumes of
natural gas in the Piceance Basin due to limited compression and pipeline
capacity in the fourth quarter of 2008.





The
increase in natural gas revenues of 24% contrasts with the reduction of oil
revenues of 29% and reflects the historically steeper decline in oil production
early in the production life cycle as compared to natural gas which was offset
by a more moderate increase in oil prices (41%) than natural gas prices (54%)
during the period.  The Partnership expects to experience continued
declines in both oil and natural gas production volumes over the wells’ life
cycles until the Wattenberg wells are recompleted.





Oil and Natural Gas
Pricing





Financial
results depend upon many factors, particularly the price of oil and natural gas
and our ability to market our production effectively.  Oil and natural
gas prices have been among the most volatile of all commodity
prices.  These price variations have a material impact on our
financial results.  Oil and natural gas prices also vary by region and
locality, 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 the majority of the partnership wells are
located.  The combination of increased drilling activity and the lack
of local markets have resulted in a local market oversupply situation from time
to time.  Such a situation existed in the Rocky Mountain Region during
2007, with production exceeding the local market demand and pipeline capacity to
non-local markets.  The result, beginning in the second quarter of
2007 and continuing through and 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 compared to the New York Mercantile Exchange, or
NYMEX, price.





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 a $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 $1.74 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 our 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 curtail its production 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.


-28-
 Index


Oil
pricing is also driven strongly by supply and demand
relationships.  In the Rocky Mountain Region for 2008, Partnership oil
sales averaged $87.16 per barrel which is below the NYMEX oil market 12-month
average monthly closing prices for 2008 of $104.42, due to supply competition
from Rocky Mountain and Canadian oil that has driven down market
prices.





The price
the Partnership receives for a large portion of the natural gas produced in the
Rocky Mountain Region is based on a market basket of prices, which may include
some natural gas sold at the CIG prices and some sold at mid-continent
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.





During
2009, oil and natural gas prices have continued to fluctuate, with oil prices on
NYMEX as high as $53.80 on March 23, 2009 and as low as $33.98 on February 12,
2009 and natural gas prices on CIG as high as $4.585 on January 7, 2009 and as
low as $2.255 on March 1, 2009.





Oil and Gas Price Risk
Management Gain (Loss), Net





The
Managing General Partner uses oil and natural gas commodity derivative
instruments to jointly manage price risk for its corporate interests as well as
sponsored drilling partnerships, including the Partnership, by area of
operation.  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.  As
of September 30, 2008, the allocation of derivative positions was fixed, based
on the current estimated future production, between the Managing General
Partners’ 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 Partners’ corporate interests and
each sponsored drilling partnership, including the Partnership, are allocated
and fixed at the time the positions are entered into based on estimated future
production.  Realized and unrealized gains and losses resulting from
derivative positions are reported on the statement of operations as “Oil and gas
price risk management gain (loss), 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.  Since December 31, 2008, through the filing of
this report, the Partnership continues to experience extreme volatility in oil
and gas prices resulting in extreme fluctuation in realized and unrealized
derivative positions.  The following table presents the realized and
unrealized gains and losses recorded for the annual periods
identified:





Years
      Ended2008
                    
                    
                    2007Realized
      gains (losses)Oil
                    
                    $
                    (432,928
                    )
                    
                    $
                    -Natural
      Gas
                    
                    
                    1,013,121
                    
                    
                    
                    207,442Total
      realized gain, net
                    
                    $
                    580,193
                    
                    
                    $
                    207,442Unrealized
      gain (loss), net
                    
                    
                    8,561,788
                    
                    
                    
                    (1,353,410
                    )Oil
      and gas price risk management, gain (loss), net
                    
                    $
                    9,141,981
                    
                    
                    $
                    (1,145,968
                    )





“Oil and
gas price risk management gain (loss), 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 Note 4,
Derivative Financial
Instruments and Note 5, Fair Value of Financial
Instruments, to the accompanying financial statements for additional
details of the Partnership’s derivative financial instruments.


-29-
 Index


In 2008,
the Partnership recorded realized gains of $0.6 million and unrealized gains of
$8.6 million, resulting in a net $9.1 million gain for the
year.  Although oil and natural gas prices increased during the first
six months of 2008, the Partnership experienced dramatic commodity price
declines during the last six months of 2008, relative to the Partnership’s
current derivative positions, which resulted in significant unrealized
derivative gains in 2008.  In 2007, the Partnership incurred a
realized gain of $0.2 million and an unrealized loss of $1.3 million, resulting
in a $1.1 million net loss for the year.  The majority of the
unrealized loss recognized for 2007 was due to increasing natural gas
prices.  When forward prices for oil and natural gas decrease as they
did throughout the second half of 2008, the Partnership’s derivative positions,
which include floors, ceilings and swaps, tend to increase in value, resulting
in unrealized gain positions.  Likewise, 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 gain
(loss), net,” occur.





Oil and Gas Derivative
Activities.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 swaps on a portion of the Partnership’s oil
and natural gas production.  Under the collar arrangements, if the
applicable index rises above the ceiling price or swap, the Managing General
Partner pays the counterparty; however, if the index drops below the floor or
swap, the counterparty pays the Managing General Partner.





The
following table identifies the Partnership’s derivative positions related to oil
and gas sales activities in effect as of December 31, 2008, on Partnership
production by area.


CollarsFloors
                                        
                                        
                                        Celings
                                        
                                        
                                        Swaps
                                        
                                        
                                        Basis
      SwapsCommodity
                                          Index/Area
                                        
                                        Quantity
      (Gas-Mmbtu Oil-Bbls)
                                        
                                        
                                        Weighted
      Average Contract
                                          Price
                                        
                                        
                                        Quantity
      (Gas-Mmbtu Oil-Bbls)
                                        
                                        
                                        Weighted
      Average Contract
                                          Price
                                        
                                        
                                        Quantity
      (Gas-Mmbtu Oil-Bbls)
                                        
                                        
                                        Weighted
      Average Contract
                                          Price
                                        
                                        
                                        Quantity
      (Gas-Mmbtu Oil-Bbls)
                                        
                                        
                                        Weighted
      Average Contract
                                          Price
                                        
                                        
                                        Fair
      Value at December 31, 2008CIGPiceance1Q
      2009
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        
                                        322,860
                                        
                                        
                                        $
                                        8.08
                                        
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        1,262,6982Q
      2009
                                        
                                        
                                        302,347
                                        
                                        
                                        
                                        5.75
                                        
                                        
                                        
                                        302,347
                                        
                                        
                                        
                                        8.90
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        622,6043Q
      2009
                                        
                                        
                                        302,347
                                        
                                        
                                        
                                        5.75
                                        
                                        
                                        
                                        302,347
                                        
                                        
                                        
                                        8.90
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        503,2674Q
      2009
                                        
                                        
                                        205,879
                                        
                                        
                                        
                                        6.64
                                        
                                        
                                        
                                        205,879
                                        
                                        
                                        
                                        10.18
                                        
                                        
                                        
                                        73,896
                                        
                                        
                                        
                                        9.20
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        845,2922010
                                        
                                        
                                        223,056
                                        
                                        
                                        
                                        6.69
                                        
                                        
                                        
                                        223,056
                                        
                                        
                                        
                                        10.83
                                        
                                        
                                        
                                        110,844
                                        
                                        
                                        
                                        9.20
                                        
                                        
                                        
                                        646,786
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        1,050,1542011
                                        
                                        
                                        98,116
                                        
                                        
                                        
                                        4.75
                                        
                                        
                                        
                                        98,116
                                        
                                        
                                        
                                        9.45
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        722,361
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        106,8622012
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        728,607
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        (293,155
                                        )2013
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        654,456
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        (438,114
                                        )$
                                        3,659,608Wattenberg
      Field1Q
      2009
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        
                                        58,887
                                        
                                        
                                        $
                                        8.07
                                        
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        229,7982Q
      2009
                                        
                                        
                                        52,314
                                        
                                        
                                        
                                        5.75
                                        
                                        
                                        
                                        52,314
                                        
                                        
                                        
                                        8.89
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        107,7263Q
      2009
                                        
                                        
                                        52,314
                                        
                                        
                                        
                                        5.75
                                        
                                        
                                        
                                        52,314
                                        
                                        
                                        
                                        8.89
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        87,0734Q
      2009
                                        
                                        
                                        35,694
                                        
                                        
                                        
                                        6.65
                                        
                                        
                                        
                                        35,694
                                        
                                        
                                        
                                        10.18
                                        
                                        
                                        
                                        12,678
                                        
                                        
                                        
                                        9.20
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        145,9852010
                                        
                                        
                                        41,376
                                        
                                        
                                        
                                        6.57
                                        
                                        
                                        
                                        41,376
                                        
                                        
                                        
                                        10.74
                                        
                                        
                                        
                                        19,016
                                        
                                        
                                        
                                        9.20
                                        
                                        
                                        
                                        108,185
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        181,9552011
                                        
                                        
                                        20,989
                                        
                                        
                                        
                                        4.75
                                        
                                        
                                        
                                        20,989
                                        
                                        
                                        
                                        9.45
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        119,810
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        19,1292012
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        122,002
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        (49,085
                                        )2013
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        108,614
                                        
                                        
                                        
                                        1.88
                                        
                                        
                                        
                                        (72,707
                                        )$
                                        649,874NYMEXOil1Q
      2009
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        
                                        13,605
                                        
                                        
                                        $
                                        90.52
                                        
                                        
                                        
                                        -
                                        
                                        
                                        $
                                        -
                                        
                                        
                                        $
                                        567,2102Q
      2009
                                        
                                        
                                        -
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        13,756
                                        
                                        
                                        
                                        90.52
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        505,4603Q
      2009
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        13,907
                                        
                                        
                                        
                                        90.52
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        466,8364Q
      2009
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        13,907
                                        
                                        
                                        
                                        90.52
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        428,4492010
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        43,382
                                        
                                        
                                        
                                        92.96
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        -
                                        
                                        
                                        
                                        1,204,181$
                                        3,172,136TOTAL
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        
                                        $
                                        7,481,618


Production and Operating
Costs





Production
and Operating Costs include production taxes and transportation costs which
generally vary with sales and production, well operating costs charged on a per
well basis and other direct costs incurred in the production
process.


-30-
 Index


As
production declines as per the historical decline curve, fixed costs increase as
a percentage of total costs.  This results in production costs per
unit to rise.  As production continues 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.  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.





Although
2008 production and operating costs decreased by $0.4 million from the previous
year, the per Mcfe basis increase is primarily due to a 30% decrease in
production and an increase in the cost of general oil field
services.  This increase was partially offset by a $0.6 million
revision of estimated 2007 and 2008 property and severance taxes based on the
results of actual taxes filed with Colorado and North Dakota taxing
agencies.





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.  Reductions in audit fees in 2008 over 2007, the year in
which the Partnership filed initial and subsequent Partnership Registration
Statements on Form 10 and Form 10/A were offset, however, by increases in
general costs due to the royalty litigation settlement.  Additional
direct costs in the amount of $119,183 were recorded in 2008 due to the royalty
litigation settlement.  For additional information regarding the
settlement, see Note 9, Commitments and Contingencies
to the accompanying financial statement included in this report.





Depreciation, Depletion and
Amortization





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.





The $4.0
million decrease in DD&A for 2008 is primarily the result of the production
level decrease of 30%.  In the fourth quarter of 2008 and 2007, the
DD&A unit cost per Mcfe increased due to the availability of the reserve
information from the annual reserve reports.  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 reserve report, resulted in the larger DD&A unit cost
increase during that period than fourth quarter 2007.




Loss on Impairment of Oil
and Gas Properties





The
Partnership recorded impairment losses of $3,839,197 for the year ended December
31, 2008 and $2,445,617 for the year ended December 31, 2007 resulting from the
downward revision to the fair value of discounted future net cash flows of
production activities in the Bakken and Nesson fields in North
Dakota.  The Partnership assesses impairment of capitalized costs of
proved oil and natural gas properties each quarter 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 management reasonably
estimates such products will be sold.  If net capitalized costs exceed
undiscounted future net cash flows, as they did for the years ended December 31,
2008 and 2007 respectively, the measurement of impairment is based on estimated
fair value which would consider future discounted cash flows.


-31-
 Index


Exploratory Dry Hole
Costs





The
Partnership incurred exploratory dry hole costs of $85,236 and $8,132,943 for
the years ended December 31, 2008 and 2007, respectively, resulting from three
exploratory wells in Colorado and two exploratory wells in North
Dakota.





Gain on Sale of Oil and Gas
Properties





For the
year ended December 31, 2008, the Partnership recognized a gain of the entire
proceeds for sale of two Wattenberg Field exploratory wells that were considered
to be commercially non-productive and were expensed in 2007 as “Dry hole
costs.”  Both Colorado wells sold at fair market value to an
unaffiliated third-party. Commercially non-productive wells are wells found to
be incapable of producing hydrocarbons in sufficient quantities to economically
warrant the expenditure of additional facility construction costs required to
deliver those quantities, to market.





Interest
Income





Interest
income decreased in 2008 compared to 2007 due to the lower levels of
undistributed revenues held by the Managing General Partner.





Liquidity and Capital
Resources





As the
Partnership has completed its drilling activities as of December 31, 2008, the
Partnership’s operations are expected to be conducted with available funds and
revenues generated from oil and natural gas production activities, with the
possible exception of recompletions and “refracs.”  It may be
necessary for the Partnership to retain Partnership revenues for the payment of
these costs, or for PDC to advance the necessary funds to the Partnership or for
the Partnership to borrow necessary funds.  The Managing General
Partner anticipates that borrowed funds will be utilized to finance Codell
recompletion activities (see Item 1, Business).  As the
Partnership will have to repay the borrowed funds plus interest, the amount of
Partnership funds available for distribution to the partners of the Partnership
will be reduced accordingly.





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 December 31, 2008, covering 55% of the Partnership’s
expected oil production and 75% of its expected natural gas production for
2009.  These contracts reduce the impact of price changes for a
substantial portion of the Partnership’s 2009 cash from
operations.  Additional derivative positions were entered into during
2008 for natural gas production through March 2011 and oil production through
December 2010 while natural gas price basis swaps cover production through
December 2013.  The current derivatives positions will change based on
changes in oil and natural gas futures markets, the view of underlying oil and
natural gas supply and demand trends and changes in volumes
produced.  Oil and natural gas derivatives as of December 31, 2008,
are detailed in Note 4, Derivative Financial
Instruments to the accompanying financial statements.


-32-
 Index


Working
Capital





The
following table sets forth the working capital position of the Partnership
excluding the unrealized losses on derivatives contracts expiring in less than
12 months from the end of each respective period.  The Partnership
believes this non-GAAP measure better reflects the Partnership’s actual working
capital.  This adjusted amount generally represents the receivables
from oil and natural gas sales for the preceding three months, offset by
corresponding production taxes payable and accrued expenses for the same
period.





Years
      Ended December 31,2008
                      
                      
                      2007Working
      capital per financial statements
                      
                      $
                      9,361,536
                      
                      
                      $
                      5,091,879Due
      from Managing General Partner - derivatives
                      
                      
                      (5,772,399
                      )
                      
                      
                      -Working
      capital excluding derivatives
                      
                      $
                      3,589,137
                      
                      
                      $
                      5,091,879





Investing
Cash Flows





The
Partnership utilized $1.3 million in capital for the development of oil and gas
properties and received $0.1 million in proceeds from the sale of two
commercially non-productive wells classified as dry holes.





Financing
and Investing Cash Flows





The
Partnership initiated monthly cash distributions to investors in May 2007 and
has distributed $20.6 million of its operating cash flows through December 31,
2007 and $26.2 million in 2008.  The following table sets forth the
annual cash distributions to the Managing General Partner and Investor Partners
for the respective periods.





Managing
                  
                  
                  InvestorYears
                  
                  General
      Partner
                  
                  
                  Partners
                  
                  
                  TotalEnded
                  
                  Distributions
                  
                  
                  Distributions
                  
                  
                  Distributions2008
                  
                  $
                  9,736,727
                  
                  
                  $
                  16,489,385
                  
                  
                  $
                  26,226,1122007
                  
                  $
                  7,638,842
                  
                  
                  $
                  13,006,686
                  
                  
                  $
                  20,645,528





Operating
Cash Flows





Net cash
provided by operating activities was $26.4 million in 2008 compared to $20.7
million in 2007, an increase of $5.7 million.  The increase in cash
provided by operating activities was due primarily to the
following:





·
            A
      $0.4 million increase in realized oil and gas price risk management gain
      (loss), net accompanied by a decrease in production and operating cost of
      7.6%, partially offset by an increase in direct costs – general and
      administrative of 13% and a decrease in oil and gas sale revenues of
      6.2%.





·
            Due
      from (to) Managing General Partner decreased due to the Partnership’s
      share of reimbursement cost paid by the Managing General
      Partner.





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.





No bank
borrowings are anticipated until such time as recompletions of the Codell
formation in the Wattenberg Field wells are undertaken by the Partnership, which
is expected to occur in 2011 or later.


-33-
 Index


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 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.





Our
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.


-34-
 Index


Exploratory
well drilling costs are initially capitalized but charged to expense if the well
is determined to be economically nonproductive.  The status of each
in-progress well is reviewed quarterly to determine the proper accounting
treatment under the successful efforts method of
accounting.  Cumulative costs on in-progress exploratory wells
(“Suspended Well Costs”) remain capitalized until their productive status
becomes known.  If an in-progress exploratory well is found to be
unsuccessful (referred to as a dry hole) prior to the issuance of financial
statements, the costs are expensed to exploratory dry hole costs.  If
a final determination about the productive status of a well cannot be made prior
to issuance of the financial statements, the well is classified as “Suspended
Well Costs” until there is sufficient time to conduct additional completion or
testing operations to evaluate the pertinent geological and engineering data
obtained.  When a final determination of a well’s productive status is
made, the well is removed from the suspended well status and the proper
accounting treatment is recorded.  The determination of an exploratory
well's ability to produce is made within one year from the completion of
drilling activities.  At December 31, 2008 and 2007, the Partnership
had no in-progress exploratory wells requiring “Suspended Well Costs”
classification.




In
accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the Partnership reviews its proved oil and
gas properties for impairment whenever events and circumstances indicate that a
decline in recoverability of their carrying value may have occurred. The
Partnership estimates the expected undiscounted future net cash flows of its oil
and gas properties on a field-by-field basis and compares such undiscounted
future net cash flows to the carrying amount of the oil and gas properties to
determine if the carrying amount is recoverable. Estimated production is
based upon prices at which management reasonably estimates such products
will be sold. These estimates of future product prices may differ from current
market prices of oil and natural gas. Any downward revisions in estimates to
Partnership reserve quantities, expectations of falling commodity prices or
rising operating costs could result in a reduction in undiscounted future net
cash flows and an impairment of our oil and gas properties. If net capitalized
costs exceed undiscounted future net cash flows, impairment is measured by the
amount by which the net capitalized costs exceed their fair value. 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, usually with a
term of two to three years, but in no cases longer than five years beyond the
derivative transaction date, which may either “swap” or “collar” a price range
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 Partnership
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 of Financial Instruments





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 delays 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.


-35-
 Index


Derivative Financial
Instruments.  The Managing General Partner uses derivative
instruments to manage the Partnership’s commodity and financial market
risks.  The Partnership currently does not use hedge accounting
treatment for its derivatives.  Derivatives are reported on the
Partnership’s accompanying balance sheets at fair value on a gross asset and
liability basis.  Changes in fair value of derivatives are recorded in
“Oil and gas price risk management, gain (loss), net,” in the Partnership’s
accompanying statements of operations.





SFAS 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.  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.





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.  Instruments included in Level 3 consist of Partnership
commodity derivatives for CIG-based natural gas swaps, NYMEX-based oil swaps,
natural gas fixed-price floor and ceiling price collars and natural gas basis
protection swaps.





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 interest’s
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.  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, the Partnership has recorded no
valuation allowance.  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 gross net fair value of Partnership commodity based derivatives as
of December 31, 2008, to be $7.5 million.


-36-
 Index


Non-Derivative Financial Assets and
Liabilities.  The carrying values of the financial instruments
comprising “Cash and cash equivalents,” “Accounts receivable,” “Accounts
payable” and “Due to (from) Managing General Partner-other” approximate fair
value due to the short-term maturities of these instruments.





Asset
Retirement Obligations





The
Partnership applies the provisions of SFAS 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 estimate lives 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 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.








Item 7A.
            Quantitative
      and Qualitative Disclosures About Market
Risk





Not
applicable








Item 8.
            Financial
      Statements and Supplementary Data





The
financial statements are attached to this Form 10-K beginning at page
F-1.








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 weaknesses described
below in Management’s Report
on Internal Control Over Financial Reporting included in this Item
9A(T).


-37-
 Index


(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 weaknesses 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 until 2009.


-38-
 Index


(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, 20007.





·
            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 will enhance operating efficiencies and provide 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.


-39-
 Index


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
two material weaknesses which were identified as of December 31, 2007, are
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, 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 and complete power to do any and all
things necessary and incident to the management and conduct of 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,
they devote the entirety of their daily time to the business and operations of
PDC.  One of the major business segments of PDC includes the operation
of the business of PDC's sponsored limited partnerships, including the
Partnership.  An element of their 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 varies 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
33 limited partnerships and other joint ventures formed over the
years.  PDC owns an interest in all of the 33 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 its 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.  Since PDC has an
interest in all Partnership wells, the operations of such wells receive the full
attention of the operations group to maximize the well's performance for both
the Partnership and PDC.





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.


-40-
 Index


PDC
employs geologists who develop prospects for drilling by PDC and who help
oversee the drilling process.  In addition, PDC has an engineering
staff that is responsible for well completions, 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
reserves of all wells at least annually and reviews 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.


-41-
 Index


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
      andOffices Held
                          
                          DirectorSince
                          
                          DirectorshipTerm ExpiresRichard
      W McCullough
                          
                          56
                          
                          Chairman,
      Chief Executive Officer, President and Director
                          
                          2007
                          
                          2010Gysle
      R. Shellum
                          
                          56
                          
                          Chief
      Financial Officer
                          
                          -
                          
                          -Eric
      R. Stearns
                          
                          50
                          
                          Executive
      Vice President
                          
                          -
                          
                          -Darwin
      L. Stump
                          
                          53
                          
                          Chief
      Accounting Officer
                          
                          -
                          
                          -Daniel
      W. Amidon
                          
                          47
                          
                          General
      Counsel and Secretary
                          
                          -
                          
                          -Barton
      R. Brookman, Jr.
                          
                          46
                          
                          Senior
      Vice President Exploration and Production
                          
                          -
                          
                          -Steven
      R. Williams
                          
                          58
                          
                          Director
                          
                          1983
                          
                          2009Vincent
      F. D'Annunzio
                          
                          56
                          
                          Director
                          
                          1989
                          
                          2010Jeffrey
      C. Swoveland
                          
                          53
                          
                          Director
                          
                          1991
                          
                          2011Kimberly
      Luff Wakim
                          
                          50
                          
                          Director
                          
                          2003
                          
                          2009David
      C. Parke
                          
                          41
                          
                          Director
                          
                          2003
                          
                          2011Anthony
      J. Crisafio
                          
                          55
                          
                          Director
                          
                          2006
                          
                          2009Joseph
      E. Casabona
                          
                          64
                          
                          Director
                          
                          2007
                          
                          2011Larry
      F. Mazza
                          
                          47
                          
                          Director
                          
                          2007
                          
                          2010





Richard
W. McCullough was appointed Chief Executive Officer and President in June
2008.  He was additionally appointed Chairman in November
2008.  Mr. McCullough joined the Company as Chief Financial Officer in
November of 2006.  A financial executive with over thirty years of
experience working both for and with utilities and energy companies, Mr.
McCullough previously held the position of President and CEO of Gasource, LLC
and has held senior positions with JP Morgan Securities, Progress Energy,
Deloitte and Touche, and the Municipal Gas Authority of Georgia.  Mr.
McCullough holds both BS and MS degrees from the University of Southern
Mississippi and was a practicing Certified Public Accountant for eight
years.





Gysle R.
Shellum, was appointed Chief Financial Officer in November
2008.  With over 25 years of energy related experience within the
accounting, finance, risk management and merger and acquisition
areas.  Mr. Shellum recently held the position of Vice President,
Finance and Special Projects at CrossTex Energy, LP.  Mr. Shellum also
served as Director of Value Capital, LLC; Chief Financial and Operating Officer
at Financial Trade Solutions; Chief Financial Officer at Duer Wagner Co.; and as
American International Petroleum Corporation’s Chief Financial
Officer.  Mr. Shellum began his career as a practicing CPA in Arthur
Andersen’s Energy Group.  Mr. Shellum is a graduate of the University
of Texas at Arlington with a BBA in Accounting.


-42-
 Index


Darwin
L. Stumpwas appointed Chief
Accounting Officer in November 2006.  Previously, Mr. Stump served as
Chief Financial Officer and Treasurer since November 2003.  Mr. Stump
has been an officer of the Company since April 1995 and held the position of
Corporate Controller since 1980 when he joined the Company.  Prior to
joining PDC, Mr. Stump was a senior accountant with Main Hurdman, Certified
Public Accountants.  Mr. Stump is a graduate of West Virginia
University with a BSBA in Accounting and a Certified Public
Accountant.





Eric R.
Stearns was appointed Executive Vice President in March 2008 after
serving as Executive Vice President of Exploration and Development since
December 2004.  Prior thereto, Mr. Stearns was Vice President of
Exploration and Development since November 2003, having previously served as
Vice President of Exploration since April 1995.  Mr. Stearns joined
PDC as a geologist in 1985 after working for Hywell, Incorporated and for
Petroleum Consultants.





Daniel
W. Amidonwas appointed General
Counsel in July of 2007.  An attorney with over 20 years of experience
working with public and private companies, Mr. Amidon recently held the position
of Vice President, Law with Wheeling-Pittsburgh Steel
Corporation.  Prior thereto, Mr. Amidon worked for J&L Specialty
Steel for twelve years in positions of increasing responsibility, ultimately
serving as the General Counsel and Secretary.  He has also practiced
with the Pittsburgh law firm of Buchanan Ingersoll for the first five years of
his career and brings extensive experience to PDC in the areas of corporate law,
contract negotiation, corporate governance, litigation management, mergers and
acquisitions, and risk management.  Mr. Amidon earned a B.A. degree
with honors from the University of Virginia in Economics and Psychology and a
J.D. degree from the Dickinson School of Law of the Pennsylvania State
University.





Barton
R. Brookman, Jr. was appointed Senior Vice President Exploration and
Production in March 2008 after serving as Vice President of Production since
joining PDC in 2005.  Mr. Brookman has over twenty years of operations
experience within the E&P sector.  Prior to joining PDC, Mr.
Brookman worked for Patina oil and gas and its predecessor Snyder Oil for 17
years in a series of jobs of increasing responsibility ending his service as
Vice President of Operations of Patina.  Mr. Brookman received a BS in
Petroleum Engineering from the Colorado School of Mines and a MS in Finance from
the University of Colorado/Denver.





Steven
R. Williams was appointed Director as part of his planned retirement in
2008.  Previous to this, Mr. Williams was Chairman of the
Board.  Until his retirement in 2008, he served as Chief Executive
Officer of the Company since January 2004, as President from March 1983 until
December 2004, and as a Director of PDC since March 1983.  Mr.
Williams serves as Chairman of the Executive Committee.





Vincent
F. D'Annunzio has been a Director since 1989.  Mr. D’Annunzio
also serves as President of Beverage Distributors, Inc. located in Clarksburg,
West Virginia and has held this position 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 been a director since 1991 and was selected as Presiding
Independent Director in 2007.  Mr. Swoveland serves as Chief Financial
Officer of Body Media and has held this position since September
2000.  Prior thereto, Mr. Swoveland was Vice President-Finance and
Treasurer of Equitable Resources Inc.  Mr. Swoveland serves as
Presiding Independent Director, and serves on the Planning and Finance
Committee.





Kimberly
Luff Wakim, has been a director since 2003.  An Attorney and
Certified Public Accountant, Ms. Wakim is a Partner with the law firm Thorp,
Reed & Armstrong LLP, joining the firm in 1990.  Ms. Wakim serves
on the Audit Committee and Nominating and Governance Committee.





David C.
Parke has been a Director since 2003.  In November 2006, Mr.
Parke joined Boenning & Scattergood, Inc. as Managing Director in their
Investment Banking Group.  Prior thereto, Mr. Parke operated as a
founder and Director of Mufson/Howe/Hunter & Company LLC, an
investment-banking firm, since 2003.  From 1992-2003 Mr. Parke was
with the corporate finance department of Investec, Inc. and its predecessor
Pennsylvania Merchant Group, Ltd., both 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.  Mr. Parke
serves as Chairman of both the Planning and Finance Committee and the
Compensation Committee.  He also serves on the Nominating and
Governance Committee and Audit Committee.


-43-
 Index


Anthony
J. Crisafiohas been a Director
since 2006.  Mr. Crisafio serves as an independent business
consultant, providing financial and operational advice to businesses, and a
business owner.  Prior thereto, he was the Chief Operating Officer of
Cinema World, Inc. and a Partner with Ernst & Young.  Mr. Crisafio
serves as chairman of the Audit Committee and serves on the Compensation
Committee.





Joseph
E. Casabona has been a Director since 2007.  Mr. 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
on the Audit Committee and the Planning and Finance Committee.





Larry F.
Mazzahas
been a Director since 2007.  Mr. Mazza was instrumental in the
formation of and is currently serving as CEO of MVB Bank, Inc. of Harrison
County, West Virginia.  Prior to the formation of MVB Bank, Mr. Mazza
served as Senior Vice President Retail Banking Manager for BB&T in West
Virginia and as President of two other local West Virginia
Banks.  Prior to his banking experience, Mr. Mazza was a CPA with a
Big-Four accounting firm.





The Audit
Committee of the Board of Directors is comprised of Directors Swoveland,
Crisafio, Parke, 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, with the exception of Mr.
Parke, 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.  Amounts paid to the Managing General Partner by the Partnership
are not used to directly compensate or reimburse PDC’s officers or
directors.  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
December 31, 2008, the Partnership had 4,497.03 units outstanding.  No
director or officer of PDC owns any units.  As of December 31, 2008,
PDC has purchased 3.5 units of Partnership interests from Investor
Partners.  PDC owns a 37% 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 Partnerships 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.


-44-
 Index


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.





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 executive officers have invested in all
of the wells owned by the Partnership prior to the drilling of each of the
wells.  Ownership by each executive in Partnership wells varies
depending on when the well was drilled and the amount of funds invested in the
program.  The aggregate ownership percentage is 0.071% of each well in
the Partnership.  The Board believes that having the executive
officers invest in wells with the company 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 billings from the Partnership’s independent registered public accounting
firm, Schneider Downs and Co., Inc. (“Schneider Downs”), of $327,661 and
$258,200 for audit fees for the period ended December 31, 2007 and 2008,
respectively.  Audit fees include amounts billed for professional
services rendered by Schneider Downs for the audit of the Partnership’s
financial statements in its Form 10 and Form 10/A for the period ended December
31, 2006 and reviews of the condensed unaudited financial statements for the
three months ended March 31, 2007 and nine months ended September 30,
2007.  Audit fees also include amounts billed for professional
services for the audit of the Partnership’s financial statements in the Annual
Report on Form 10K and Form 10K/A for the year ended December 31, 2007 and
reviews of the condensed unaudited financial statements included in the
Partnership’s Form 10/Q for the quarters ended September 30, 2007 and March 31,
June 30, and September 30, 2008.





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.


-45-
 Index


Item15.
            Exhibits,
      Financial Statement Schedules





(a)
            The
      index to Financial Statements is located on page
  F-1.





(b)
            Exhibit
      Index.





Incorporated
      by ReferenceExhibit
      Number
                                                
                                                Exhibit
      Description
                                                
                                                Form
                                                
                                                Sec
      File Number
                                                
                                                Exhibit
                                                
                                                Filing
      Date
                                                
                                                Filed
      Herewith3.1
                                                
                                                Limited
      Partnership Agreement
                                                
                                                10-12G/A
      Amend 1
                                                
                                                000-52787
                                                
                                                3
                                                
                                                12/24/20073.2
                                                
                                                Certificate
      of limited partnership which reflects the organization of the Partnership
      under West Virginia law
                                                
                                                10-12G/A
      Amend 1
                                                
                                                000-52787
                                                
                                                3.1
                                                
                                                12/24/200710.1
                                                
                                                Form
      of assignment of leases to the Partnership
                                                
                                                10-12G/A
      Amend 1
                                                
                                                000-52787
                                                
                                                10.1
                                                
                                                12/24/200710.2
                                                
                                                Drilling
      and operating agreement between PDC as Managing General Partner of the
      Partnership
                                                
                                                10-12G/A
      Amend 1
                                                
                                                000-52787
                                                
                                                10.2
                                                
                                                12/24/200710.3
                                                
                                                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
                                                
                                                
                                                
                                                02/27/200910.4
                                                
                                                Gas
      Purchase and Processing Agreement between Duke Energy Field Services,
      Inc.; United States Exploration, Inc.; and Petroleum Development
      Corporation, dated October 28, 1999 (filed by PDC as Managing General
      Partner for Rockies Region 2007 Limited Partnership*)
                                                
                                                10-12G/A
      Amend 3
                                                
                                                000-53201
                                                
                                                10.3
                                                
                                                3/31/200910.5
                                                
                                                Gas
      Purchase and Processing Agreement between Natural Gas Associates, a
      Colorado partnership, and Aceite Energy Corporation, Walker Exploratory
      Program 1982-A Limited and Creek Cattle Company, dated October 14, 1983
      (filed by PDC as Managing General Partner for Rockies Region 2007 Limited
      Partnership*)
                                                
                                                10-12G/A
      Amend 3
                                                
                                                000-53201
                                                
                                                10.4
                                                
                                                3/31/2009




-46-
 Index




Incorporated
      by ReferenceExhibit
      Number
                                    
                                    Exhibit
      Description
                                    
                                    Form
                                    
                                    Sec
      File Number
                                    
                                    Exhibit
                                    
                                    Filing
      Date
                                    
                                    Filed
      Herewith10.6
                                    
                                    Gas
      Purchase and Processing Agreement between Natural Gas Associates, a
      Colorado partnership, and SHF Partnership, a Colorado general partnership,
      Trailblazer Oil and Gas, Inc. Alfa Resources, Inc., Pulsar Oil and Gas,
      Inc., Overthrust Oil Royalty Corporation, Corvette Petroleum Ltd., Robert
      Lanari, an individual, and Toby A Martinez, an individual, dated September
      21, 1983 (filed by PDC as Managing General Partner for Rockies Region 2007
      Limited Partnership*)
                                    
                                    10-12G/A
      Amend 3
                                    
                                    000-53201
                                    
                                    10.5
                                    
                                    3/31/200910.7
                                    
                                    Domestic
      Crude Oil Purchase Agreement with ConocoPhillips Company, dated January 1,
      1993, as amended by agreements with Teppco Crude Oil, LLC dated August 2,
      2007; September 24, 2007; October 17, 2007; January 7, 2008; January 15,
      2008; and April 17, 2008 (filed by PDC as Managing General Partner for
      Rockies Region 2007 Limited Partnership*)
                                    
                                    10-12G/A Amend
      3
                                    
                                    000-53201
                                    
                                    10.6
                                    
                                    3/31/200910.8
                                    
                                    Gas
      Purchase Agreement between Williams Production RMT Company, Riley Natural
      Gas Company and Petroleum Development Corporation, dated as of June 1,
      2006 (filed by PDC as Managing General Partner for Rockies Region 2007
      Limited Partnership*)
                                    
                                    10-12G/Amend
      3
                                    
                                    000-53201
                                    
                                    10.7
                                    
                                    3/31/2009


-47-
 Index


Incorporated
      by ReferenceExhibit
      Number
                                                  
                                                  Exhibit
      Description
                                                  
                                                  Form
                                                  
                                                  Sec
      File Number
                                                  
                                                  Exhibit
                                                  
                                                  Filing
      Date
                                                  
                                                  Filed
      Herewith10.9
                                                  
                                                  Domestic
      Crude Oil Purchase Agreement between Shell Trading (US) Company and
      Petroleum Development Corporation, dated September 13,
    2007*
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  X23.1
                                                  
                                                  Consent
      of Ryder Scott Company, L.P., Petroleum Consultants
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  X31.1
                                                  
                                                  Rule
      13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum
      Development Corporation, the Managing General Partner of the
      Partnership.
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  X31.2
                                                  
                                                  Rule
      13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum
      Development Corporation, the Managing General Partner of the
      Partnership.
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  X32.1
                                                  
                                                  Title
      18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)
      Certification by Chief Executive Officer of Petroleum Development
      Corporation, the Managing General Partner of the
    Partnership.
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  X32.2
                                                  
                                                  Title
      18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002)
      Certification by Chief Financial Officer of Petroleum Development
      Corporation, the Managing General Partner of the
    Partnership.
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  
                                                  X
  _______________


*A
confidential treatment request pursuant to Exchange Act rule 24b.2 was filed
with the SEC with respect to portions of these agreements.


-48-
 Index


SIGNATURES





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.





Rockies
Region 2006 Limited Partnership


By its
Managing General Partner


Petroleum
Development Corporation





By/s/ Richard W.
McCullough


Richard
W. McCullough


Chairman,
Chief Executive Officer, and President


March 31
, 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,
      Chief Executive Officer, and President
                                                                              
                                                                              March
      31 , 2009Richard W.
      McCullough
                                                                              
                                                                              Petroleum
      Development Corporation,Managing
      General Partner of the Registrant(Principal
      executive officer)/s/ Gysle R. Shellum
                                                                              
                                                                              Chief
      Financial Officer
                                                                              
                                                                              March
      31 , 2009Gysle R.
      Shellum
                                                                              
                                                                              Petroleum
      Development Corporation,Managing
      General Partner of the Registrant(Principal
      financial officer)/s/ Darwin L. Stump
                                                                              
                                                                              Chief
      Accounting Officer
                                                                              
                                                                              March
      31 , 2009Darwin L.
      Stump
                                                                              
                                                                              Petroleum
      Development Corporation,Managing
      General Partner of the Registrant(Principal
      accounting officer)/s/ Steven R. Williams
                                                                              
                                                                              Director
                                                                              
                                                                              March
      31 , 2009Steven R.
      Williams
                                                                              
                                                                              Petroleum
      Development Corporation,Managing
      General Partner of the Registrant/s/ Anthony J. Crisafio
                                                                              
                                                                              Director
                                                                              
                                                                              March
      31 , 2009Anthony J.
      Crisafio
                                                                              
                                                                              Petroleum
      Development Corporation,Managing
      General Partner of the Registrant/s/ Jeffrey C. Swoveland
                                                                              
                                                                              Director
                                                                              
                                                                              March
      31 , 2009Jeffrey C.
      Swoveland
                                                                              
                                                                              Petroleum
      Development Corporation,Managing
      General Partner of the Registrant/s/ Joseph E. Casabona
                                                                              
                                                                              Director
                                                                              
                                                                              March
      31 , 2009Joseph E.
      Casabona
                                                                              
                                                                              Petroleum
      Development Corporation,Managing
      General Partner of the Registrant


-49-
 Index




ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Index to
Financial Statements





Report
      of Independent Registered Public Accounting Firm
                F-2Balance
      Sheets – December 31, 2008 and 2007
                F-3Statements
      of Operations – For the Years Ended December 31, 2008 and
    2007
                F-4Statements
      of Partners' Equity –For the Years Ended December 31, 2008 and
      2007
                F-5Statements
      of Cash Flows – For the Years Ended December 31, 2008 and
    2007
                F-6Notes
      to Financial Statements
                F-7Supplemental
      Oil and Gas Information - Unaudited
                F-25


F-1
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP








REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM





To the
Partners of the Rockies Region 2006 Limited Partnership,





We have
audited the accompanying balance sheets of Rockies Region 2006 Limited
Partnership as of December 31, 2008 and 2007 and the related statements of
operations, partners’ equity and cash flows for the years then ended. 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 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. The Partnership is not required to
have, nor were we engaged to perform, an audit of its internal control over
financial reporting. Our audits included consideration of internal controls over
financial reporting as a basis for designing audit procedures that are
appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the Partnership’s internal control over
financial reporting. Accordingly, we express no such opinion. An audit also
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
 
 In our
opinion, the financial statements referred to above present fairly, in all
material respects, the financial position of Rockies Region 2006 Limited
Partnership as of December 31, 2008 and 2007, and the results of its operations
and its cash flows for the years then ended in conformity with accounting
principles generally accepted in the United States of America.
    Pittsburgh,
Pennsylvania
 March 31,
2009




F-2
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP








Balance
Sheets


December
31, 2008 and 2007








Assets
                        
                        2008
                        
                        
                        2007Current
      assets:Cash
      and cash equivalents
                        
                        $
                        203,462
                        
                        
                        $
                        1,183,810Accounts
      receivable
                        
                        
                        3,555,821
                        
                        
                        
                        8,524,415Oil
      Inventory
                        
                        
                        45,750
                        
                        
                        
                        -Due
      from Managing General Partner-derivatives, net
                        
                        
                        5,772,399
                        
                        
                        
                        -Interest
      receivable
                        
                        
                        -
                        
                        
                        
                        40,000Total
      current assets
                        
                        
                        9,577,432
                        
                        
                        
                        9,748,225Oil
      and gas properties, successful efforts method
                        
                        
                        97,606,701
                        
                        
                        
                        101,836,026Wells
      in progress
                        
                        
                        -
                        
                        
                        
                        114,427Oil
      and gas properties, at cost
                        
                        
                        97,606,701
                        
                        
                        
                        101,950,453Less
      accumulated depreciation, depletion and amortization
                        
                        
                        (25,706,395
                        )
                        
                        
                        (15,882,832
                        )Oil
      and gas properties, net
                        
                        
                        71,900,306
                        
                        
                        
                        86,067,621Due
      from Managing General Partner-derivatives
                        
                        
                        1,709,219
                        
                        
                        
                        -Total
      Assets
                        
                        $
                        83,186,957
                        
                        
                        $
                        95,815,846Liabilities and Partners'
      EquityCurrent
      liabilities:Accounts
      payable and accrued expenses
                        
                        $
                        206,320
                        
                        
                        $
                        598,390Due
      to Managing General Partner-derivatives, net
                        
                        
                        -
                        
                        
                        
                        1,080,170Due
      to Managing General Partner-other, net
                        
                        
                        9,576
                        
                        
                        
                        2,977,786Total
      current liabilities
                        
                        
                        215,896
                        
                        
                        
                        4,656,346Asset
      retirement obligations
                        
                        
                        775,083
                        
                        
                        
                        775,652Total
      liabilities
                        
                        
                        990,979
                        
                        
                        
                        5,431,998Commitments
      and contingenciesPartners'
      equity:Managing
      General Partner
                        
                        
                        25,476,495
                        
                        
                        
                        28,539,072Limited
      Partners - 4,497.03 units issued and outstanding
                        
                        
                        56,719,483
                        
                        
                        
                        61,844,776Total
      Partners' equity
                        
                        
                        82,195,978
                        
                        
                        
                        90,383,848Total
      Liabilities and Partners' Equity
                        
                        $
                        83,186,957
                        
                        
                        $
                        95,815,846








See
accompanying notes to financial statements.


F-3
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP








Statements
of Operations


For the
Years Ended December 31, 2008 and 2007








2008
                    
                    
                    2007Revenues:Oil
      and gas sales
                    
                    $
                    29,959,247
                    
                    
                    $
                    31,942,229Oil
      and gas price risk management gain (loss), net
                    
                    
                    9,141,981
                    
                    
                    
                    (1,145,968
                    )Total
      revenues
                    
                    
                    39,101,228
                    
                    
                    
                    30,796,261Operating
      costs and expenses:Production
      and operating costs
                    
                    
                    5,135,146
                    
                    
                    
                    5,557,327Direct
      costs - general and administrative
                    
                    
                    673,877
                    
                    
                    
                    596,183Depreciation,
      depletion and amortization
                    
                    
                    11,496,628
                    
                    
                    
                    15,476,390Exploratory
      dry hole expense
                    
                    
                    85,236
                    
                    
                    
                    8,132,943Loss
      on impairment of oil and gas properties
                    
                    
                    3,839,197
                    
                    
                    
                    2,445,617Accretion
      of asset retirement obligations
                    
                    
                    38,362
                    
                    
                    
                    36,852Total
      operating costs and expenses
                    
                    
                    21,268,446
                    
                    
                    
                    32,245,312Income
      (loss) from operations
                    
                    
                    17,832,782
                    
                    
                    
                    (1,449,051
                    )Gain
      on sale of oil and gas properties
                    
                    
                    120,000
                    
                    
                    
                    -Interest
      expense
                    
                    
                    -
                    
                    
                    
                    (7,543
                    )Interest
      income
                    
                    
                    85,460
                    
                    
                    
                    173,679Net
      income (loss)
                    
                    $
                    18,038,242
                    
                    
                    $
                    (1,282,915
                    )Net
      income (loss) allocated to partners
                    
                    $
                    18,038,242
                    
                    
                    $
                    (1,282,915
                    )Less
      Managing General Partner interest in net income (loss)
                    
                    
                    6,674,150
                    
                    
                    
                    (474,679
                    )Net
      income (loss) allocated to Investor Partners
                    
                    $
                    11,364,092
                    
                    
                    $
                    (808,236
                    )Net
      income (loss) per Investor Partner unit
                    
                    $
                    2,527
                    
                    
                    $
                    (180
                    )Investor
      Partner units outstanding
                    
                    
                    4,497
                    
                    
                    
                    4,497








See
accompanying notes to financial statements.


F-4
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP








Statements
of Partners' Equity


For the
Years Ended December 31, 2008 and 2007








ManagingInvestor
                
                
                GeneralPartners
                
                
                Partner
                
                
                TotalBalance,
      December 31, 2006
                
                $
                75,659,698
                
                
                $
                36,652,593
                
                
                $
                112,312,291Distributions
      to partners
                
                
                (13,006,686
                )
                
                
                (7,638,842
                )
                
                
                (20,645,528
                )Net
      loss
                
                
                (808,236
                )
                
                
                (474,679
                )
                
                
                (1,282,915
                )Balance,
      December 31, 2007
                
                
                61,844,776
                
                
                
                28,539,072
                
                
                
                90,383,848Distributions
      to partners
                
                
                (16,489,385
                )
                
                
                (9,736,727
                )
                
                
                (26,226,112
                )Net
      income
                
                
                11,364,092
                
                
                
                6,674,150
                
                
                
                18,038,242Balance,
      December 31, 2008
                
                $
                56,719,483
                
                
                $
                25,476,495
                
                
                $
                82,195,978








See
accompanying notes to financial statements.


F-5
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP








Statements
of Cash Flows


For the
Years Ended December 31, 2008 and 2007








2008
                    
                    
                    2007Cash
      flows from operating activities:Net
      income (loss)
                    
                    $
                    18,038,242
                    
                    
                    $
                    (1,282,915
                    )Adjustments
      to reconcile net income to net cash provided by operating
      activities:Loss
      on impairment of oil and gas properties
                    
                    
                    3,839,197
                    
                    
                    
                    2,445,617Depreciation,
      depletion and amortization
                    
                    
                    11,496,628
                    
                    
                    
                    15,476,390Accretion
      of asset retirement obligations
                    
                    
                    38,362
                    
                    
                    
                    36,852Gain
      on sale of oil and gas properties
                    
                    
                    (121,335
                    )
                    
                    
                    -Unrealized
      loss (gain) on derivative transactions
                    
                    
                    (8,561,788
                    )
                    
                    
                    1,353,410Exploratory
      dry hole expense
                    
                    
                    85,236
                    
                    
                    
                    8,132,943Changes
      in operating assets and liabilities:Decrease
      (increase) in accounts receivable
                    
                    
                    4,968,594
                    
                    
                    
                    (7,295,731
                    )Increase
      in oil inventory
                    
                    
                    (45,750
                    )
                    
                    
                    -Decrease
      (increase) in interest receivable
                    
                    
                    40,000
                    
                    
                    
                    (40,000
                    )(Decrease)
      increase in accounts payable and accrued expenses
                    
                    
                    (392,070
                    )
                    
                    
                    484,917(Decrease)
      increase  in due from/to Managing General
Partner
                    
                    
                    (4,036,867
                    )
                    
                    
                    1,363,261Net
      cash provided by operating activities
                    
                    
                    25,348,449
                    
                    
                    
                    20,674,744Cash
      flows from investing activities:Capital
      expenditures for oil and gas properties
                    
                    
                    (222,685
                    )
                    
                    
                    -Proceeds
      from sale of oil and gas properties
                    
                    
                    120,000
                    
                    
                    
                    -Net
      cash used in investing activities
                    
                    
                    (102,685
                    )
                    
                    
                    -Cash
      flows from financing activities:Distributions
      to Partners
                    
                    
                    (26,226,112
                    )
                    
                    
                    (20,645,528
                    )Net
      cash used in financing activities
                    
                    
                    (26,226,112
                    )
                    
                    
                    (20,645,528
                    )Net
      increase (decrease) in cash and cash equivalents
                    
                    
                    (980,348
                    )
                    
                    
                    29,216Cash
      and cash equivalents, beginning of period
                    
                    
                    1,183,810
                    
                    
                    
                    1,154,594Cash
      and cash equivalents, end of period
                    
                    $
                    203,462
                    
                    
                    $
                    1,183,810Supplemental
      disclosure of non-cash activity:Asset
      retirement obligation, with corresponding increase to oil and gas
      properties
                    
                    $
                    (38,931
                    )
                    
                    $
                    382,558








See
accompanying notes to financial statements.


F-6
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





Note 1 -
Organization





The
Rockies Region 2006 Limited Partnership (the “Partnership” or the “Registrant”)
was organized as a limited partnership on September 7, 2006, 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 as of the date of organization.





Purchasers
of partnership units subscribed to and fully paid for 47.25 units of limited
partner interests and 4,449.78 units of additional general partner interests at
$20,000 per unit.  As of December 31, 2008 there are 2,028 Investor
Partners.  Petroleum Development Corporation (“PDC”) has been
designated the Managing General Partner of the Partnership and has a 37%
ownership in the Partnership. Generally, throughout the term of the Partnership,
revenues, costs, and cash distributions are allocated 63% 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 37% to the Managing General Partner.  As of December 31, 2008, the
Managing General Partner has repurchased 3.5 units of Partnership interests from
Investor Partners at an average price of $11,429 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.





Through
the executive drilling program, certain executive officers have invested in the
wells owned by the Partnership.  Ownership by each executive in
Partnership wells varies depending on when the well was drilled and the amount
of funds invested in the program.  The aggregate ownership percentage
is 0.071% 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.





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.  The balance in the Partnership’s
account is temporarily insured by the Federal Deposit Insurance Corporation, or
FDIC, in an amount up to $250,000 through December 31, 2009, after such date the
FDIC limit will revert to $100,000 unless the temporary limit is extended or
made permanent.  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.


F-7
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





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 our industry is the concentration of oil and
natural gas sales to a 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 undistributed oil and natural gas revenues by
PDC to the Partnership 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) MGP – Other,
net.”  Refer to note 3.  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 and other
partnerships for which PDC serves as Managing General
Partner.




Additionally,
certain amounts recorded by the Partnership as liabilities in the account “Due
from (to) Managing General Partner - other” were funded by the Managing General
Partner and are currently held in escrow for distribution to litigants, which
represents unpaid royalties on Partnership production through 2008 which will be
deducted from future Partner distributions.  These amounts, which
total $146,023, represent the Partnership’s share of the court approved
royalty litigation settlement, more fully described in Note 9, Commitments and
Contingencies.





Additionally,
in 2008 the Partnership incurred additional drilling costs of $1,068,657 in
excess of drilling advances paid to the Managing General Partner. This amount
has been recorded as a liability in the account “Due from (to) Managing General
Partner - other” and will be funded by a reduction in future
distributions.





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.


F-8
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





Oil and 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 of each year.  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 required to be used solely for the drilling of oil
and natural gas wells.  Accordingly, all such funds were advanced to
the Managing General Partner as of December 31, 2006.  Amounts that
have not yet been used by the Managing General Partner for drilling activities
are reported under the caption “Drilling advances to Managing General
Partner.”  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 Depletion, Depreciation and Amortization (“DD&A”)
expense, a change in our estimated reserves could have an effect on our net
income.





Exploratory
well drilling costs are initially capitalized but charged to expense if the well
is determined to be nonproductive.  The status of each in-progress
well is reviewed quarterly to determine the proper accounting treatment under
the successful efforts method of accounting. Cumulative costs on in-progress
wells (“Suspended Well Costs”) remain capitalized until their productive status
becomes known. If an in-progress exploratory well is found to be unsuccessful
(referred to as a dry hole) prior to the issuance of financial statements, the
costs incurred as of the balance sheet date are expensed to exploratory dry hole
costs. If a final determination about the productive status of a well is unable
to be made prior to issuance of the financial statements, the well is classified
as “Suspended Well Costs” until there is sufficient time to conduct additional
completion or testing operations to evaluate the pertinent geological and
engineering data obtained. When a final determination of a well’s productive
status is made, the well is removed from the suspended well status and the
proper accounting treatment is recorded. The determination of an exploratory
well's ability to produce is made within one year from the completion of
drilling activities.  At December 31, 2008 and 2007, the Partnership
had no in-progress exploratory wells requiring “Suspended Well Cost”
classification.


In
accordance with Statement of Financial Accounting Standards, or SFAS No. 144,
Accounting for the Impairment
or Disposal of Long-Lived Assets, the Partnership reviews its proved oil
and gas properties for impairment whenever events and circumstances indicate
that a decline in recoverability of their carrying value may have occurred. The
Partnership estimates the expected undiscounted future net cash flows of its oil
and gas properties on a field-by-field basis and compares such undiscounted
future net cash flows to the carrying amount of the oil and gas properties
to determine if the carrying amount is recoverable. Estimated production is
based upon prices at which management reasonably estimates such products will be
sold. These estimates of future product prices may differ from current market
prices of oil and natural gas. Any downward revisions to the Partnership’s
estimates of future production or product prices could result in an impairment
of the Partnership’s oil and natural gas properties in subsequent periods. If
net capitalized costs exceed undiscounted future net cash flows, impairment
is measured by the amount by which the net capitalized costs exceed their fair
value. The Partnership has incurred impairment losses to date of
$13,414,497 on its proved oil and natural gas properties.


F-9
 Index


ROCKIES
REGION 2006 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 Partnership
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 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 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.





The
Partnership sold natural gas and oil to four customers: Shell Trading (US)
Company (“Shell”), DCP Midstream LP (“DCP”), Teppco Crude Oil, LP (“Teppco”) and
Williams Production RMT (“Williams”), which accounted for 10%, 12%, 33% and 45%,
respectively, of the Partnership’s total natural gas and oil sales for the year
ended December 31, 2008.  These same four customers accounted for 12%,
11%, 42% and 35%, respectively, of the Partnership’s total natural gas and oil
sales for the year ended December 31, 2007.





Asset Retirement
Obligations





The
Partnership applies the provisions of SFAS No. 143, Accounting for Asset Retirement
Obligationsand 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.


F-10
 Index


ROCKIES
REGION 2006 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.





During
2008 and 2007, none of the Partnership’s derivative instruments qualified for
use of hedge accounting under the provisions of SFAS No.
133.  Accordingly, the Partnership recognizes all derivative
instruments as either assets or liabilities on its balance sheets at fair value,
and changes in the derivatives' fair values are recorded on a net basis 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, gain (loss),
net.”





See Note
4, Derivative Financial
Instruments, and Note 5, Fair Value of 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, respectively.





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 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 Sheet.





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. Production
and operating cost for 2008 include a $0.6 million downward revision of
estimated 2007 and 2008 property and severance taxes based on the results of
actual taxes filed with Colorado and North Dakota taxing
agencies.





Recently Adopted Accounting
Standards





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 delays 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.  The Partnership is currently
evaluating the potential effect that the nonfinancial assets and liabilities
provisions of SFAS No. 157 will have on its financial statements when adopted in
2009.  See Note 5, Fair Value
Measurements.


F-11
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





In
October 2008, the FASB issued FSP No. FAS 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 No.
FAS 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 SFAS No. 141 (revised 2007), Business Combinations (“SFAS
No. 141R”).  SFAS No. 141R requires an acquirer to recognize the
assets acquired, the liabilities assumed and any noncontrolling interest in the
acquiree at their acquisition-date fair values.  SFAS No. 141R 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, SFAS No. 141R requires that
acquisition-related costs be expensed as incurred.  The provisions of
SFAS No. 141R will become effective for acquisitions completed on or after
January 1, 2009; however, the income tax provisions of SFAS No. 141R will become
effective as of that date for all acquisitions, regardless of the acquisition
date.  SFAS No. 141R amends SFAS 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.  SFAS No. 141R
further amends SFAS No. 109 and 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
December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements—An Amendment of ARB No.
51.  SFAS No. 160 states that accounting and reporting for
minority interests will be recharacterized as non-controlling interests and
classified as a component of equity.  Additionally, SFAS 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.  SFAS No. 160 is effective as
of the beginning of an entity’s first fiscal year beginning after December 15,
2008.  The Partnership is evaluating the impact that SFAS No. 160 will
have, if any, on its financial statements and related disclosures when adopted
in 2009.


F-12
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





In March
2008, the FASB issued SFAS 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.  SFAS No. 161 is effective for financial
statements issued for fiscal years and interim periods beginning after November
15, 2008, with early application encouraged.  The Partnership is
currently evaluating the impact that SFAS No. 161 will have, if any, on its
financial statements and related disclosures when adopted in 2009.





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 to 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.





Reclassifications





Certain
amounts in the prior period have been reclassified to conform with the current
year classifications with no effect on previously reported net income or
Partners’ equity.








Note 3 -
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.  Undistributed oil and natural gas revenues are recorded
on the balance sheet under the caption “Accounts receivable.”  The
portion due from third parties amounted to $1,173,324 and $3,488,760 as of
December 31, 2008 and 2007, respectively, with the remaining portion due from
the Managing General Partner.  The fair value of the Partnership’s
portion of unexpired derivative instruments is recorded on the balance sheet
under the caption “Due from the Managing General Partner – derivatives, net” in
the case of net unrealized gains or “Due to  Managing General Partner
– derivatives, net” in the case of net unrealized losses.  Realized
gains or losses that have not yet been distributed to the Partnership are
included in the balance sheet captions “Due from (to) Managing General
Partner-other”, respectively.  Undistributed realized gains amounted
to $2,099,787 and $146,084 as of December 31, 2008 and 2007, respectively. 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.”





The
following table presents transactions with the Managing General Partner and its
affiliates for years ended December 31, 2008 and 2007.





Year
      Ended December 31,2008
                      
                      
                      2007Well
      charges (1)(2)
                      
                      $
                      655,306
                      
                      
                      $
                      508,340Gas
      marketing, supplies and equipment (3)
                      
                      
                      2,399,284
                      
                      
                      
                      2,336,455Gathering,
      compression and processing fees (4)
                      
                      
                      297,848
                      
                      
                      
                      280,403Direct
      costs - general and administrative (5)
                      
                      
                      673,877
                      
                      
                      
                      557,083Distributions
      (6)
                      
                      
                      9,736,727
                      
                      
                      
                      7,638,842


F-13
 Index




ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





1. The
Partnership entered into a Drilling and Operating Agreement with the Managing
General Partner to drill and complete the Partnership's wells at cost plus the
Managing General Partner's drilling compensation of 12.6% of the total well
cost. Total well cost includes the cost of leases acquired from the Managing
General Partner and drilling costs.  The drilling compensation
percentage of 12.6% was determined prior to formation of the Partnership and
disclosed in the offering documents.  The drilling compensation
amounts were calculated using this rate in accordance with the offering
documents.  The Managing General Partner sells undeveloped prospects
(leases) to the Partnership to drill the Partnership’s wells.  Leases
are sold to the Partnership at the lower of the Managing General Partner’s cost
to purchase the lease or the leases’ fair market
value.   Drilling costs include an overhead charge to the
Managing General Partner of 11⁄2% of each well’s Authority for
Expenditure.





If the
Managing General Partner provides other services in the drilling and completion
of the wells, it charges those services at its cost, not to exceed competitive
rates charged in its area of operation by unaffiliated persons and these charges
are included in the total well cost when determining the Managing General
Partner's drilling compensation.





Cost,
when used with respect to services, generally means the reasonable, necessary,
and actual expense incurred in providing the services, determined in accordance
with generally accepted accounting principles.  The cost of the well
also includes all ordinary costs of drilling, testing and completing the
well.





The well
costs charged to the Partnership are proportionately reduced to the extent the
Partnership acquires less than 100% of the working interest in a
prospect.  The amount of compensation that the Managing General
Partner could earn as a result of these arrangements depends on the degree to
which it provides services for the wells, and the number and type of wells that
are drilled.  If the Managing General Partner supplies other goods and
services to the Partnership, it is required to supply them at cost, and they
will be included in the total well costs for determining the Managing General
Partner's and the investor partners' contributions, the division of oil and
natural gas revenues, and calculation of the Managing General Partner's drilling
compensation.





The
following table presents the usage of the drilling advances to Managing General
Partner based on the drilling activities of the Managing General
Partner:





Year
      Ended
                    
                    
                    Year
      EndedDecember
      31, 2008
                    
                    
                    December
      31, 2007Purchase
      of leases
                    
                    $
                    21,606
                    
                    
                    $
                    908,880Drilling
      costs
                    
                    
                    1,209,579
                    
                    
                    
                    79,387,844Drilling
      compensation
                    
                    
                    155,129
                    
                    
                    
                    10,117,387Drilling
      advances to Managing General Partner
                    
                    
                    (317,657
                    )
                    
                    
                    (90,414,111
                    )








In 2008
the Partnership incurred $1,068,657 of additional drilling costs of in excess of
drilling advances paid to the Managing General Partner which have been recorded
as a liability in the account “Due from (to) Managing General Partner - other”
and will be funded by a reduction in future distributions.





During
2006, the Partnership retained interest income earned of $1.1 million on amounts
held in escrow during drilling operations from September 7, 2006 (date of
inception) to December 31, 2006.  This amount was utilized as
additional funds available for drilling activities in 2007.


F-14
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





2.  Under
the Drilling and Operating Agreement, the Managing General Partner, as operator
of the wells, receives the following from the Partnership when the wells begin
producing:


·
            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 operator
receives a monthly fee for each producing well based upon competitive industry
rates for operations and field supervision and $100 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.





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 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.





3. 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.





4. 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.





5. 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.


F-15
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





6. The
Agreement provides for the allocation of cash distributions 63% to the Investor
Partners and 37% to the Managing General Partner.  For additional
disclosure regarding the allocation of cash distributions, refer to Note 6,
Partners’ Equity and Cash
Distributions.





Additionally,
refer to Note 4, 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 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 leases is acceptable for purposes of the
Partnership.





Note 4 -
Derivative Financial
Instruments





The
Partnership is exposed to the effect of market fluctuations in the prices of oil
and natural gas as they relate to oil and natural gas sales.  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.  Partnership policy prohibits the use of oil and natural
gas derivative instruments for speculative purposes.





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.  These contracts consist of fixed-price swaps, basis swaps and
collars.  Credit risk is the failure of the counterparty to perform
under the terms of the derivative contract.  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 seeks to diversify
counterparty exposure by entering into transactions with high-quality
counterparties including two investment grade financial
institutions.  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 this evaluation, the Managing General Partner has
determined that the impact of the nonperformance of counterparties on the fair
value of the Partnership’s derivative instruments is
insignificant.  The Managing General Partner has experienced no
counterparty defaults during the years ended December 31, 2008 and 2007 and no
valuation allowance has been recorded by the Partnership.  The recent
disruption in the credit market has had a significant impact on a number of
financial institutions.  While Managing General Partner believes that
its procedures are sufficient and customary, no amount of analysis can guarantee
performance in these uncertain times.





Risk Management
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
instruments. 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
Colorado Interstate Gas Index, or CIG, based contracts for Colorado gas
production and New York Mercantile Exchange, or NYMEX, based contracts for
Colorado oil production.  In addition to the fixed-price 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.  Through October 31, 2007, the Partnership’s
natural gas derivative instruments were comprised of natural gas floors and
collars while its oil derivative instruments were comprised of oil
“floors.”


F-16
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





·
            For
      swap instruments, PDC, as Managing General Partner, receives a fixed price
      for the hedged commodity and pays a floating market price to the
      counterparty.  The fixed-price payment and the floating-price
      payment are netted, resulting in a net amount due to or from the
      counterparty.





·
            Basis
      protection swaps are arrangements that guarantee a price differential for
      natural gas valued at a specified pricing point, or hub.  For
      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.





·
            Collars
      contain a fixed floor price (put) and ceiling price (call).  If
      the market price exceeds the ceiling strike price or falls below the fixed
      floor strike price, PDC, as Managing General Partner, receives the fixed
      floor price and pays the market price.  If the market price is
      between the ceiling and the floor strike price, no payments are due from
      either party.





·
            Floors
      contained a floor price (put) whereby PDC, as Managing General Partner,
      received from the counterparty the floor price if the commodity market
      price fell below the floor strike price, but received no payment when the
      commodity market price exceeded 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 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.





Valuation
of a contract’s fair value is performed internally.  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.  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
                    
                    
                    2007Derivative
      net assets (liabilities)Oil
      and gas sales activities:Fixed-price
      natural gas swaps
                    
                    $
                    2,284,527
                    
                    
                    $
                    -Natural
      gas collars
                    
                    
                    2,325,365
                    
                    
                    
                    193,427Natural
      gas basis protection swaps
                    
                    
                    (300,410
                    )
                    
                    
                    -Natural
      gas floors
                    
                    
                    -
                    
                    
                    
                    4,239Fixed-price
      oil swaps
                    
                    
                    3,172,136
                    
                    
                    
                    (1,277,836
                    )Estimated
      net fair value of derivative instruments
                    
                    $
                    7,481,618
                    
                    
                    $
                    (1,080,170
                    )





At
December 31, 2008 and 2007, the maximum term for the derivative positions listed
above is 60 months and 12 months, respectively.


F-17
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





The
following table identifies the fair value of commodity based derivatives as
classified in the Partnership’s balance sheets





December
      31,2008
                  
                  
                  2007Classification
      in the Balance SheetsFair
      value of current assetsDue
      from Managing General Partner-derivatives
                  
                  $
                  5,772,399
                  
                  
                  $
                  -Fair
      value of other assets-long termDue
      from Managing General Partner-derivatives
                  
                  
                  1,709,219
                  
                  
                  
                  -7,481,618
                  
                  
                  
                  -Fair
      value of current liabilitiesDue
      to Managing General Partner-derivatives
                  
                  
                  -
                  
                  
                  
                  1,080,170Net
      fair value of commodity based derivatives- asset
    (liability)
                  
                  $
                  7,481,618
                  
                  
                  $
                  (1,080,170
                  )


F-18
 Index


ROCKIES
REGION 2006 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.





For
      the year ended December 31,2008
                      
                      
                      2007Realized
      gains (losses)Oil
                      
                      $
                      (432,928
                      )
                      
                      $
                      -Gas
                      
                      
                      1,013,121
                      
                      
                      
                      207,442Total
      realized gain, net
                      
                      
                      580,193
                      
                      
                      
                      207,442Unrealized
      gain (loss)
                      
                      
                      8,561,788
                      
                      
                      
                      (1,353,410
                      )Oil
      and gas price risk management gain (loss), net
                      
                      $
                      9,141,981
                      
                      
                      $
                      (1,145,968
                      )





Note 5 –
Fair Value of
Financial Instruments





Derivative Financial
Instruments





Determination of fair
value.  The Partnership measures fair value 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 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.  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.  Thus, no valuation allowance has been recorded by the
Partnership as of December 31, 2008.  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.





Valuation
hierarchy.  SFAS 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.  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.





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.


F-19
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





Level 3 – Unobservable inputs
for the asset or liability, including situations where there is little, if any,
market activity for the asset or liability.  Instruments included in
Level 3 consist of Partnership commodity derivatives for CIG based natural gas
swaps, NYMEX based oil swaps, natural gas fixed-price floor and ceiling price
collars and natural gas basis protection swaps.





SFAS No.
157 requires fair value measurements to be separately disclosed by level within
the fair value hierarchy and requires a separate reconciliation of fair value
measurements categorized as Level 3.  The following table presents for
each hierarchy level, the Partnership’s assets and liabilities including both
current and non-current portions, measured at fair value on a recurring basis as
of December 31, 2008:





Level
      1
                  
                  
                  Level
      2
                  
                  
                  Level
      3
                  
                  
                  TotalAssets:.Commodity
      based derivatives
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  7,481,618
                  
                  
                  $
                  7,481,618Net
      fair value of commodity based derivatives
                  
                  $
                  -
                  
                  
                  $
                  -
                  
                  
                  $
                  7,481,618
                  
                  
                  $
                  7,481,618





The table
below sets forth a reconciliation of our 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.





YearEndedDecember
      31, 2008Fair
      value, net asset (liability), beginning of period
                    
                    $
                    (1,080,170
                    )Realized
      and unrealized gains (losses) included in Oil and gas price risk
      management gain (loss), net
                    
                    
                    9,141,981Purchases,
      sales, issuances and settlements, net
                    
                    
                    (580,193
                    )Fair
      value, net asset (liability), end of period
                    
                    $
                    7,481,618





Non-Derivative Financial
Instruments





The
carrying values of the financial instruments comprising “Cash and cash
equivalents,” “Accounts receivable,” “Accounts payable” and “Due to (from)
Managing General Partner-other ” approximate fair value due to the short-term
maturities of these instruments.





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.


F-20
 Index


ROCKIES
REGION 2006 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, taking into
account the Managing General Partner's capital contribution, which was equal to
43.07% of the Investor Partners’ initial capital.


ManagingInvestor
                          
                          
                          GeneralPartners
                          
                          
                          PartnerPartnership
      Revenue:Oil
      and gas sales
                          
                          
                          63
                          %
                          
                          
                          37
                          %Oil
      and gas price risk management gain (loss)
                          
                          
                          63
                          %
                          
                          
                          37
                          %Sale
      of productive properties
                          
                          
                          63
                          %
                          
                          
                          37
                          %Sale
      of equipment
                          
                          
                          63
                          %
                          
                          
                          37
                          %Sale
      of undeveloped leases
                          
                          
                          63
                          %
                          
                          
                          37
                          %Interest
      income
                          
                          
                          63
                          %
                          
                          
                          37
                          %Partnership
      Costs:Administrative
      costs (a)
                          
                          
                          0
                          %
                          
                          
                          100
                          %Broker-dealer
      commissions and expenses/syndication costs (a)
                          
                          
                          100
                          %
                          
                          
                          0
                          %Cost
      of oil and gas properties: (b)Undeveloped
      lease costs
                          
                          
                          0
                          %
                          
                          
                          100
                          %Tangible
      well costs
                          
                          
                          0
                          %
                          
                          
                          100
                          %Intangible
      drilling costs
                          
                          
                          100
                          %
                          
                          
                          0
                          %Managing
      general partner's drilling compensation
                          
                          
                          100
                          %
                          
                          
                          0
                          %Other
      costs and expenses:Management
      fee (c)
                          
                          
                          100
                          %
                          
                          
                          0
                          %Production
      and operating costs (d)
                          
                          
                          63
                          %
                          
                          
                          37
                          %Depreciation,
      depletion and amortization expense
                          
                          
                          63
                          %
                          
                          
                          37
                          %Accretion
      of asset retirement obligations
                          
                          
                          63
                          %
                          
                          
                          37
                          %Direct
      costs (e)
                          
                          
                          63
                          %
                          
                          
                          37
                          %


(a)
            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.




(b)
              These
      allocations are for tax reporting purposes and do not impact cash
      distributions.




(c)
            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.





(d)
            Represents
      operating costs incurred after the completion of productive wells,
      including monthly per-well charges paid to the Managing General
      Partner.





(e)
            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.


F-21
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





The
following table presents the allocation of net income (loss) to the Investor
Partners and the Managing General Partner for each of the periods
presented.





Year
      Ended December 31,2008
                        
                        
                        2007Managing
      General Partner interest in net income37%
      of net income allocated to the Managing General Partner
                        
                        $
                        6,674,150
                        
                        
                        $
                        (474,679
                        )Investor
      Partner interest in net income63%
      of net income allocated to the Investor Partners
                        
                        
                        11,364,092
                        
                        
                        
                        (808,236
                        )Net
      income allocated to Partners
                        
                        $
                        18,038,242
                        
                        
                        $
                        (1,282,915
                        )





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 Partnership initiated monthly cash distributions to
Investor Partners in May 2007.  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 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-served basis.





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.  During
2008, the Managing General Partner made first quarter unit repurchases in
February 2008 of 2.5 units at an average price of $10,000 per unit and second
quarter unit repurchases in April 2008 of 1.0 unit at an average price of
$15,000 per unit.  No other units were repurchased during the
remainder of 2008.





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 63% to the Investor Partners and 37% to the Managing General
Partner throughout the term of the Partnership.  The Partnership has
paid cash distributions each month since May 2007.  Distributions for
the years ended December 31, 2008 and 2007 were $26,226,112 and $20,645,528,
respectively.


F-22
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





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 September 7, 2006 with payments made for all planned
drilling and completion costs for the Partnership in 2006.  Costs
capitalized for these activities at December 31, 2008 and 2007 are as
follows:





2008
                    
                    
                    2007Leasehold
      costs
                    
                    $
                    846,070
                    
                    
                    $
                    822,436Development
      costs
                    
                    
                    96,760,631
                    
                    
                    
                    101,013,590Oil
      and gas properties, successful efforts method
                    
                    
                    97,606,701
                    
                    
                    
                    101,836,026Wells
      in progress
                    
                    
                    -
                    
                    
                    
                    114,427Oil
      and gas properties at cost
                    
                    $
                    97,606,701
                    
                    
                    $
                    101,950,453





Wells in
progress represents expenditures incurred for wells for which drilling and/or
completion activities have commenced but had not been
completed.  Development costs include the Partnership’s asset
retirement obligations.





Gain
on Sale of Oil and Gas Properties





For the
year ended December 31, 2008, the Partnership recognized a gain in the amount of
the entire proceeds, in the sale of two Wattenberg Field exploratory wells that
were considered to be commercially non-productive which were expensed in 2007 as
“Dry hole costs.”  Both Colorado wells were sold at fair market value
to an unaffiliated third-party. Commercially non-productive wells are wells
found to be incapable of producing hydrocarbons in sufficient quantities to
economically warrant the expenditure of additional facility construction costs
required to deliver those quantities to market.





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
                  
                  
                  2007Balance
      at beginning of period
                  
                  $
                  775,652
                  
                  
                  $
                  356,242New
      liabilities incurred (relief of obligations)
                  
                  
                  (38,931
                  )
                  
                  
                  382,558Accretion
      expense
                  
                  
                  38,362
                  
                  
                  
                  36,852Balance
      at end of period
                  
                  $
                  775,083
                  
                  
                  $
                  775,652





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





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 Partnership’s Managing General Partner in the District Court, Weld County,
Colorado alleging that the Managing General Partner underpaid royalties on gas
produced from wells operated by the Managing General Partner in the State of
Colorado (the "Droegemueller Action").  The plaintiff seeks
declaratory relief and to recover an unspecified amount of compensation for
underpayment of royalties paid by the Managing General Partner pursuant to
leases.  The Managing General Partner moved the case to Federal Court
on June 28, 2007, and on July 10, 2007, the Managing General Partner filed its
answer and affirmative defenses.


F-23
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Notes to
Financial Statements





A second
similar Colorado class action suit was filed against the Managing General
Partner in the U.S. District Court for the District of Colorado on December 3,
2007 by Ted Amsbaugh, et al.  On December 31, 2007, the plaintiffs in
this second action filed a motion to consolidate the case with the Droegemueller
action above.  On January 28, 2008, the Court granted the plaintiff’s
motion to consolidate the action with the Droegemueller Action.





The court
approved a stay in proceedings until September 22, 2008 while the parties
pursued mediation of the matter.  Based on the mediation held on May
28, 2008, and subsequent negotiations, $39,100 was accrued by the Partnership
for this litigation for the year ended December 31, 2007.  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 64 wells in the Wattenberg field





On
October 10, 2008, the court issued preliminary approval of the settlement
agreement. The portion of the proposed settlement related to the Partnership’s
wells for all periods through December 31, 2008 is $146,023.  During
2008, an additional amount of $106,923 plus legal costs of $12,260 were recorded
to fully accrue for the settlement through December 31, 2008.  In
November 2008, the Managing General Partner paid into an escrow account, on
behalf of the Partnership, amounts due under the settlement.  These
amounts will be deducted from future Partnership
distributions.  Notice of the settlement was mailed to members of the
class action suit in the fourth quarter 2008 and the final settlement approval
hearing is expected on April 7, 2009.


F-24
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Supplemental
Oil and Gas Information - Unaudited





Costs Incurred in Oil and
Gas Property Exploration and Development Activities





Costs
incurred in oil and gas property exploration and development are presented
below:





Year
      ended December 31,2008
                    
                    
                    2007Leasehold
      costs
                    
                    $
                    23,634
                    
                    
                    $
                    -Developmental
      costs
                    
                    
                    1,182,472
                    
                    
                    
                    -Exploration
      costs
                    
                    
                    85,236
                    
                    
                    
                    8,132,943Total
      costs incurred
                    
                    $
                    1,291,342
                    
                    
                    $
                    8,132,943





Development
costs include costs incurred to gain access to and prepare development well
locations for drilling, to drill and equip development wells, recompletions and
to provide facilities to extract, treat, gather and store oil and
gas.  Development costs also include estimated asset retirement costs
as discussed in Note 8.  Exploration costs include costs incurred in
examining specific areas that are considered to have prospects of containing oil
and gas reserves.





Net Proved Oil and 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 which are
United States properties.  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.


F-25
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Supplemental
Oil and Gas Information - Unaudited





Below are
the net quantities of net proved reserves of the Partnership’s
Properties.





Oil
      (MBbl)2008
                            
                            
                            2007Proved
      reserves:Beginning
      of year
                            
                            
                            1,803
                            
                            
                            
                            961Extensions,
      discoveries, and improved recovery,less related cost
                            
                            
                            -
                            
                            
                            
                            654Revisions
      of previous estimates
                            
                            
                            (482
                            )
                            
                            
                            485Production
                            
                            
                            (149
                            )
                            
                            
                            (298
                            )End
      of Year
                            
                            
                            1,172
                            
                            
                            
                            1,802Gas
      (MMcf)2008
                            
                            
                            2007Proved
      reserves:Beginning
      of year
                            
                            
                            24,343
                            
                            
                            
                            9,014Extensions,
      discoveries, and improved recovery,less related cost
                            
                            
                            -
                            
                            
                            
                            10,571Revisions
      of previous estimates
                            
                            
                            (1,938
                            )
                            
                            
                            7,895Production
                            
                            
                            (2,532
                            )
                            
                            
                            (3,136
                            )End
      of Year
                            
                            
                            19,873
                            
                            
                            
                            24,344December
      31,Proved Developed Reserves
                            
                            2008
                            
                            
                            2007Oil
      (MBbl)
                            
                            
                            596
                            
                            
                            
                            1,137Natural
      Gas (MMcf)
                            
                            
                            16,820
                            
                            
                            
                            21,292





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


·
            MMcf
      – One million cubic feet


F-26
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Supplemental
Oil and 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.





December
      31,2008
                  
                  
                  2007(in
      thousands)Future
      estimated revenues
                  
                  $
                  137,362
                  
                  
                  $
                  311,970Future
      estimated production costs
                  
                  
                  (50,832
                  )
                  
                  
                  (78,302
                  )Future
      estimated development costs
                  
                  
                  (11,119
                  )
                  
                  
                  (12,218
                  )Future
      net cash flows
                  
                  
                  75,411
                  
                  
                  
                  221,45010%
      annual discount for estimated timing of cash flows
                  
                  
                  (34,742
                  )
                  
                  
                  (103,770
                  )Standardized
      measure of discounted future estimated net cash flows
                  
                  $
                  40,669
                  
                  
                  $
                  117,680





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:





December
      31,2008
                    
                    
                    2007(in
      thousands)Sales
      of oil and gas production, net of production costs
                    
                    $
                    (24,824
                    )
                    
                    $
                    (26,385
                    )Net
      changes in prices and production costs
                    
                    
                    (55,675
                    )
                    
                    
                    13,287Extensions,
      discoveries, and improved recovery,less related cost
                    
                    
                    -
                    
                    
                    
                    47,012Development
      cost incurred during the period
                    
                    
                    -
                    
                    
                    
                    -Revisions
      of previous quantity estimates
                    
                    
                    (9,697
                    )
                    
                    
                    36,666Accretion
      of discount
                    
                    
                    10,286
                    
                    
                    
                    2,887Timing
      and other
                    
                    
                    2,899
                    
                    
                    
                    12,628Net
      change
                    
                    $
                    (77,011
                    )
                    
                    $
                    86,095





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.


F-27
 Index


ROCKIES
REGION 2006 LIMITED PARTNERSHIP





Supplemental
Oil and 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.





Year
      End PriceAs
      of December 31,
                    
                    Oil
      (Bbls)
                    
                    
                    Gas
      (Mcf)2008
                    
                    $
                    37.28
                    
                    
                    $
                    4.712007
                    
                    
                    82.42
                    
                    
                    
                    6.71





F-28