v2.4.0.6
Document Entity Information Document (USD $)
12 Months Ended
Dec. 31, 2012
Feb. 28, 2013
Jun. 30, 2012
Entity Information      
Entity Registrant Name PDC 2002 B LTD PARTNERSHIP    
Entity Central Index Key 0001224950    
Current Fiscal Year End Date --12-31    
Entity Filer Category Smaller Reporting Company    
Document Type 10-K    
Document Period End Date Dec. 31, 2012    
Document Fiscal Year Focus 2012    
Document Fiscal Period Focus FY    
Amendment Flag false    
Entity Common Stock, Shares Outstanding   0.00  
Additional General Partnership Units Outstanding   0.00  
Entity Well-Known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Public Float     $ 0
v2.4.0.6
Condensed Balance Sheets (Unaudited) Statement (USD $)
Dec. 31, 2012
Dec. 31, 2011
Current assets:    
Cash and cash equivalents $ 10,137 $ 10,261
Accounts receivable 21,527 39,117
Crude oil inventory 24,499 11,174
Due from Managing General Partner-derivatives 180,165 201,175
Total current assets 236,328 261,727
Natural gas and crude oil properties, successful efforts method, at cost 3,167,657 7,774,445
Less: Accumulated depreciation, depletion and amortization (2,270,162) (5,592,847)
Natural gas and crude oil properties, net 897,495 2,181,598
Due from Managing General Partner-derivatives 0 157,086
Other assets 49,653 42,200
Total Assets 1,183,476 2,642,611
Current liabilities:    
Accounts payable and accrued expenses 2,522 4,951
Due to Managing General Partner-derivatives 81,917 87,900
Due to Managing General Partner-other, net 67,520 98,359
Total current liabilities 151,959 191,210
Due to Managing General Partner-derivatives 0 77,860
Asset retirement obligations 223,265 208,823
Total liabilities 375,224 477,893
Commitments and contingent liabilities      
Partners' equity:    
Managing General Partner 232,462 500,410
Limited Partners - 559.02 units issued and outstanding 575,790 1,664,308
Total Partners' equity 808,252 2,164,718
Total Liabilities and Partners' Equity $ 1,183,476 $ 2,642,611
v2.4.0.6
Balance Sheet Parentheticals (Parentheticals)
Dec. 31, 2012
Dec. 31, 2011
Balance Sheet Parentheticals [Abstract]    
Limited Partners' Capital Account, Units Issued 559.02 559.02
Limited Partners' Capital Account, Units Outstanding 559.02 559.02
v2.4.0.6
Statements of Operations (Unaudited) Statement (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Revenues:    
Natural gas, NGLs and crude oil sales $ 328,029 $ 618,793
Commodity price risk management gain, net 43,298 162,038
Total revenues 371,327 780,831
Operating costs and expenses:    
Natural gas, NGLs and crude oil production costs 263,214 253,578
Direct costs - general and administrative 127,801 308,164
Depreciation, depletion and amortization 208,705 345,783
Accretion of asset retirement obligations 14,442 9,815
Impairment of natural gas and crude oil properties 1,078,355 328,097
Total operating costs and expenses 1,692,517 1,245,437
Loss from continuing operations (1,321,190) (464,606)
Interest Income 21 86
Net loss (1,321,169) (464,520)
Net loss allocated to partners (1,321,169) (464,520)
Less: Managing General Partner interest in net loss (264,234) (92,904)
Net loss allocated to Investor Partners $ (1,056,935) $ (371,616)
Net loss per Investor Partner unit (1,891) (665)
Investor Partner units outstanding 559.02 559.02
v2.4.0.6
Statement of Partners' Equity Statement (USD $)
Total
Investor Partners
Managing General Partner
Balance at Dec. 31, 2010 $ 2,674,294 $ 2,076,646 $ 597,648
Change in Partners' Equity:      
Distributions to Partners (45,056) (40,722) (4,334)
Net loss (464,520) (371,616) (92,904)
Balance at Dec. 31, 2011 2,164,718 1,664,308 500,410
Change in Partners' Equity:      
Distributions to Partners (35,297) (31,583) (3,714)
Net loss (1,321,169) (1,056,935) (264,234)
Balance at Dec. 31, 2012 $ 808,252 $ 575,790 $ 232,462
v2.4.0.6
Statements of Cash Flows (Unaudited) Statement (USD $)
12 Months Ended
Dec. 31, 2012
Dec. 31, 2011
Cash flows from operating activities:    
Net loss $ (1,321,169) $ (464,520)
Adjustments to net income (loss) to reconcile to net cash from operating activities:    
Depreciation, depletion and amortization 208,705 345,783
Accretion of asset retirement obligations 14,442 9,815
Unrealized (gain) loss on derivative transactions 94,253 (127,824)
Impairment of natural gas and crude oil properties 1,078,355 328,097
Changes in assets and liabilities:    
Accounts receivable 17,590 (6,045)
Crude oil inventory (13,325) 4,898
Other assets (7,453) (7,672)
Accounts payable and accrued expenses (2,429) (903)
Due to Managing General Partner-other, net (30,839) 3,717
Net cash from operating activities 38,130 85,346
Cash flows from investing activities:    
Capital expenditures for natural gas and crude oil properties (2,957) (40,310)
Net cash from investing activities (2,957) (40,310)
Cash flows from financing activities:    
Distributions to Partners (35,297) (45,056)
Net cash from financing activities (35,297) (45,056)
Net change in cash and cash equivalents (124) (20)
Cash and cash equivalents, beginning of period 10,261 10,281
Cash and cash equivalents, end of period 10,137 10,261
Supplemental disclosure of non-cash activity:    
Asset retirement obligation, with corresponding change in natural gas and crude oil properties $ 0 $ 44,358
v2.4.0.6
General and Basis of Presentation
12 Months Ended
Dec. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]
GENERAL

PDC 2002-B Limited Partnership (“Partnership” or the “Registrant”) was organized in 2002 as a limited partnership, in accordance with the laws of the State of West Virginia, for the purpose of engaging in the exploration and development of natural gas and crude oil properties. Business operations commenced upon closing of an offering for the private placement of Partnership units. Upon funding, this Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes PDC Energy, Inc. (“PDC”) to conduct and manage this Partnership's business. In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner is authorized to manage all activities of this Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2012, there were 500 limited partners in this Partnership (“Investor Partners”). PDC is the designated Managing General Partner of this Partnership and owns a 20% Managing General Partner ownership in this Partnership. According to the terms of the Agreement, revenues, costs and cash distributions of this Partnership are allocated 80% to the Investor Partners, which are shared pro rata based upon the number of units in this Partnership and 20% to the Managing General Partner. The Managing General Partner may repurchase Investor Partner units under certain circumstances provided by the Agreement, upon request of an individual Investor Partner. For more information about the Managing General Partner's limited partner unit repurchase program, see Note 8, Partners' Equity and Cash Distributions. Through December 31, 2012, the Managing General Partner had repurchased 40.4 units of Partnership interests from the Investor Partners at an average price of $3,660 per unit. As of December 31, 2012, the Managing General Partner owned 25.78% of this Partnership.
v2.4.0.6
Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2012
Accounting Policies [Abstract]  
Significant Accounting Policies [Text Block]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management's Estimates

The preparation of this Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires this Partnership to make estimates and assumptions that affect the amounts reported in this Partnership's financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas, natural gas liquids (“NGLs”) and crude oil sales revenue, proved reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments.

Basis of Presentation

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of this Partnership.

Cash and Cash Equivalents. This Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. This Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution. The balance in this Partnership's account is insured by Federal Deposit Insurance Corporation, up to $250,000. This Partnership has not experienced losses in any such accounts to date and limits this Partnership's exposure to credit loss by placing its cash and cash equivalents with a high-quality financial institution.

Accounts Receivable and Allowance for Doubtful Accounts. This Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil. This Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by this Partnership's Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers. No allowance for doubtful accounts was deemed necessary at December 31, 2012 or 2011.

Commitments. As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of this Partnership's wells as required by governmental agencies. If a government agency were required to access these performance bonds to cover plugging, reclaiming or abandonment costs on a Partnership well, this Partnership would be obligated to fund any amounts in excess of funds previously withheld by the Managing General Partner to cover these expenses.

Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market.

Derivative Financial Instruments. This Partnership is exposed to the effect of market fluctuations in the prices of natural gas and crude oil. The Managing General Partner employs established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. The Managing General Partner's policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments are recorded in this Partnership's statements of operations and this Partnership's net income is subject to greater volatility than if this Partnership's derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to this Partnership's natural gas and crude oil sales and the realized gain or loss upon the settlement of these instruments are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to this Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to this Partnership and net realized losses are deducted from this Partnership's cash distributions generated from production. This Partnership bears its proportionate share of counterparty risk.

The validation of the derivative instrument's fair value is performed by the Managing General Partner. While the Managing General Partner uses common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments, and Note 4, Derivative Financial Instruments, for a discussion of this Partnership's derivative fair value measurements and a summary fair value table of open positions as of December 31, 2012 and 2011.

Natural Gas and Crude Oil Properties. This Partnership accounts for its natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, and developmental dry hole costs are capitalized and depreciated or depleted by the units-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the units-of-production method based on estimated proved reserves. This Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator this Partnership's estimated quarter-end reserves, adjusted to add back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. See Supplemental Natural Gas, NGLs and Crude Oil Information - Unaudited, Net Proved Reserves, included at the end of these financial statements and accompanying notes elsewhere in this report for additional information regarding this Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to this Partnership, after deducting syndication costs and a one-time management fee was, used solely for the drilling of natural gas and crude oil wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude oil which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to prepare a reserve and economic evaluation of this Partnership's properties on a well-by-well basis as of December 31. Additionally, this Partnership adjusts reserves for major well rework or abandonment during the year, as needed. The process of estimating and evaluating natural gas, NGLs and crude oil 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 represent this Partnership's 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 this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on this Partnership's net income or loss.

Proved Property Impairment. This Partnership assesses its producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs, or carrying value, 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 the commodities to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to this Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of this Partnership's proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges are included in the statement of operations line item impairment of natural gas and crude oil properties, with a corresponding reduction to natural gas and crude oil properties and accumulated depreciation, depletion and amortization line items on the balance sheet.

Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which this Partnership produces natural gas, NGLs and crude oil. This Partnership's share of these taxes is expensed to the account “Natural gas, NGLs and crude oil production costs.” This Partnership's production taxes payable are included in the caption “Accounts payable and accrued expenses” on this Partnership's balance sheets.

Income Taxes. Since the taxable income or loss of this Partnership is reported in the separate tax returns of the individual investor partners, no provision has been made for income taxes by this Partnership.

Asset Retirement Obligations. This Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, this Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in 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, revisions to estimated retirement costs and changes in the estimated timing of settling retirement obligations. See Note 6, Asset Retirement Obligations, for a reconciliation of the changes in this Partnership's asset retirement obligation activity.

Revenue Recognition. Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this Partnership's natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas, NGLs and crude oil 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 contract 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 and quality of the natural gas.

Recent Accounting Standards

Fair Value Measurement

On May 12, 2011, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and were effective for public entities during interim and annual periods beginning after December 15, 2011. Early application was not permitted. With the exception of the disclosure requirements, the adoption of these changes did not have a significant impact on this Partnership's financial statements.
v2.4.0.6
Fair Value of Financial Instruments
12 Months Ended
Dec. 31, 2012
Fair Value Disclosures [Abstract]  
Fair Value Disclosures [Text Block]
FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivative Financial Instruments

Determination of fair value. This Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires this Partnership to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as:

Level 1 - Quoted prices (unadjusted) for identical assets or liabilities in active markets.

Level 2 - Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and 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.

The Managing General Partner measures the fair value of this Partnership's derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of the Managing General Partner's credit standing on the fair value of derivative liabilities and the effect of the Managing General Partner's counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position.

The Managing General Partner validates its fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While the Managing General Partner uses common industry practices to develop its valuation techniques, changes in the Managing General Partner's pricing methodologies or the underlying assumptions could result in significantly different fair values. While the Managing General Partner believes its valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

The Managing General Partner has evaluated the credit risk of the counterparties holding the derivative assets, which are primarily financial institutions who are also lenders in the Managing General Partner's corporate credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on the Managing General Partner's evaluation, the Managing General Partner has determined that the potential impact of nonperformance of its counterparties on the fair value of this Partnership's derivative instruments was not significant.
This Partnership's fixed-price swaps and basis swaps are included in Level 2 and its natural gas collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, this Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

 
Balance Sheet
 
December 31, 2012
 
December 31, 2011
 
Line Item
 
 Level 2
 
 Level 3
 
 Total
 
 Level 2
 
 Level 3
 
 Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity-based derivatives
Due from Managing General Partner-derivatives
 
$
180,165

 
$

 
$
180,165

 
$
192,906

 
$
8,269

 
$
201,175

Non-Current
 
 
 
 
 
 
 
 
 
 
 
 
 
 Commodity-based derivatives
Due from Managing General Partner-derivatives
 

 

 

 
157,086

 

 
157,086

 Total assets
 
 
180,165

 

 
180,165

 
349,992

 
8,269

 
358,261

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 
81,917

 

 
81,917

 
87,900

 

 
87,900

Non-Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 

 

 

 
77,860

 

 
77,860

 Total liabilities
 
 
81,917

 

 
81,917

 
165,760

 

 
165,760

 Net asset
 
 
$
98,248

 
$

 
$
98,248

 
$
184,232

 
$
8,269

 
$
192,501


The following table presents a reconciliation of this Partnership's Level 3 measured at fair value:
 
Year ended
 
December 31, 2012
 
December 31, 2011
 Fair value, net asset, beginning of period
$
8,269

 
$
12,277

 Changes in fair value included in statement of operations line item:
 
 
 
 Commodity price risk management gain, net
637

 
6,256

 Settlements
(8,906
)
 
(10,264
)
 Fair value, net asset, end of period
$

 
$
8,269

 
 
 
 
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
 

 
 
December 31, 2012 and 2011, respectively, included in statement of operations line item:
 
 
 
 Commodity price risk management gain, net
$

 
$
4,768

The significant unobservable input used in the fair value measurement of this Partnership's derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of this Partnership's Level 3 derivative contracts.
    
See Note 4, Derivative Financial Instruments, for additional disclosure related to this Partnership's derivative financial instruments.

Non-Derivative Financial Assets and Liabilities

The carrying values of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments.

See Note 2, Summary of Significant Accounting Policies, Natural Gas and Crude Oil Properties and Asset Retirement Obligations, for a discussion of how this Partnership determined fair value for these assets and liabilities.
v2.4.0.6
Derivative Financial Instruments
12 Months Ended
Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments Disclosure [Text Block]
DERIVATIVE FINANCIAL INSTRUMENTS

This Partnership's results of operations and operating cash flows are affected by changes in market prices for natural gas, NGLs and crude oil. To manage a portion of this Partnership's exposure to price volatility from producing natural gas and crude oil, the Managing General Partner utilizes an economic hedging strategy for this Partnership's natural gas and crude oil sales in which PDC, as Managing General Partner, enters into derivative contracts on behalf of this Partnership to protect against price declines in future periods. While the Managing General Partner structures these derivatives to reduce this Partnership's exposure to changes in price associated with the derivative commodities, they also limit the benefit this Partnership might otherwise have received from price increases in the physical market. The Managing General Partner believes this Partnership's derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2012, this Partnership had derivative instruments in place for all of its anticipated natural gas production through 2013 totaling 50,617 MMBtu. Partnership policy prohibits the use of natural gas and crude oil derivative instruments for speculative purposes.

The Managing General Partner uses natural gas and crude oil commodity derivative instruments to manage price risk for PDC, as well as its sponsored drilling partnerships. The Managing General Partner sets these instruments for PDC and the various partnerships managed by PDC jointly by area of operations, whereby the allocation of derivative positions between PDC and each partnership is set at a fixed quantity. New positions have specific designations relative to the applicable partnership.

As of December 31, 2012, this Partnership's derivative instruments were comprised of commodity fixed-price swaps and basis protection swaps.

Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; and
Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG basis protection swaps, which traditionally have negative differentials to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty.

The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying statements of operations:
 
 
Year ended December 31,
 
 
2012
 
2011
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains For the Current Period
 
Total
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains For the Current Period
 
Total
Commodity price risk management gain, net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
113,274

 
$
24,277

 
$
137,551

 
$
18,864

 
$
15,350

 
$
34,214

Unrealized gains (losses)
 
(113,274
)
 
19,021

 
(94,253
)
 
(18,864
)
 
146,688

 
127,824

Total
$

 
$
43,298

 
$
43,298

 
$

 
$
162,038

 
$
162,038

v2.4.0.6
Concentration of Risk
12 Months Ended
Dec. 31, 2012
Risks and Uncertainties [Abstract]  
Concentration Risk Disclosure [Text Block]
CONCENTRATION OF RISK

Accounts Receivable. This Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. This Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by this Partnership's Managing General Partner. Inherent to this Partnership's industry is the concentration of natural gas, NGLs and crude oil sales to a limited number of customers. This industry concentration has the potential to impact this Partnership's overall exposure to credit risk in that its customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions.

As of December 31, 2012 and 2011, this Partnership did not record an allowance for doubtful accounts. In making the estimate for receivables that are uncollectible, the Managing General Partner considers, among other things, subsequent collections, historical write-offs and overall creditworthiness of this Partnership's customers. It is reasonably possible that the Managing General Partner's estimate of uncollectible receivables will change periodically. Historically, neither PDC, nor any of the other partnerships managed by this Partnership's Managing General Partner, have experienced significant losses from uncollectible accounts receivable. This Partnership did not incur any losses on accounts receivable for the years ended December 31, 2012 and 2011.

Major Customers. The following table presents the individual customers constituting 10% or more of total revenues:
 
 
Year ended December 31,
Major Customer
 
2012
 
2011
Suncor Energy Marketing, Inc.
 
42%
 
44%
WPX Energy Rocky Mountain, LLC
 
32%
 
30%
DCP Midstream, LP
 
17%
 
23%


Derivative Counterparties. The Managing General Partner's derivative arrangements expose this Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions who are also lenders under the Managing General Partner's revolving credit facility as counterparties to its derivative contracts. To date, the Managing General Partner has had no counterparty default losses. The Managing General Partner has evaluated the credit risk of this 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. Based on this evaluation, the Managing General Partner has determined that the potential impact of nonperformance of the Managing General Partner's counterparties on the fair value of this Partnership's derivative instruments was not significant.
v2.4.0.6
Asset Retirement Obligations
12 Months Ended
Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]  
Asset Retirement Obligation Disclosure [Text Block]
ASSET RETIREMENT OBLIGATIONS

The following table presents the changes in carrying amounts of the asset retirement obligations associated with this Partnership's working interest in natural gas and crude oil properties:

 
Year ended December 31,
 
2012
 
2011
 
 
 
 
Balance at beginning of year
$
208,823

 
$
154,650

Revisions in estimated cash flows

 
44,358

Accretion expense
14,442

 
9,815

Balance at end of year
$
223,265

 
$
208,823



The revisions in estimated cash flows during 2011 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of wells in the Wattenberg Field. These cost increases related mostly to the costs of cement and construction materials and third-party and internal support services on a per well basis. The revision in the asset retirement obligation did not have an immediate effect in the 2011 statement of operations as the increase in the revised obligation will be accreted and the offsetting capitalized amount will be depreciated over the useful lives of respective wells.
v2.4.0.6
Commitments and Contingencies
12 Months Ended
Dec. 31, 2012
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Disclosure [Text Block]
COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Neither this Partnership nor PDC, in its capacity as the Managing General Partner of this Partnership, are party to any pending legal proceeding that PDC believes would have a materially adverse effect on this Partnership's business, financial condition, results of operations or liquidity.

Environmental

Due to the nature of the oil and gas industry, this Partnership is exposed to environmental risks. The Managing General Partner has various policies and procedures in place to prevent environmental contamination and mitigate the risks from environmental contamination. The Managing General Partner conducts periodic reviews to identify changes in this Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. These liabilities are reduced as remediation efforts are completed or are adjusted as a consequence of subsequent periodic reviews. Liabilities for environmental remediation efforts are included in line item captioned “Accounts payable and accrued expenses” on the balance sheet.

During the year ended December 31, 2012, as a result of the Managing General Partner's periodic review, there were no new material environmental remediation projects identified by the Managing General Partner for this Partnership. As of December 31, 2012 and December 31, 2011, accrued environmental remediation liabilities, which were included in line item captioned “Accounts payable and accrued expenses” on the balance sheets, were insignificant.

The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2012 which have not been provided for or would otherwise have a material impact on this Partnership's financial statements; however, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on this Partnership's properties.
v2.4.0.6
Partners' Equity and Cash Distributions
12 Months Ended
Dec. 31, 2012
Equity [Abstract]  
Partners' Capital Notes Disclosure [Text Block]
PARTNERS' EQUITY AND CASH DISTRIBUTIONS

Partners' Equity

Limited Partner Units. A Limited Partner unit represents the individual interest of an individual investor partner in this Partnership. No public market exists or will develop for the units. While units of this Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner. Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the Unit Repurchase Program.

Allocation of Partners' Interest. The following table presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of this Partnership:
 
 
 
 
Managing
 
 
Investor
 
General
 
 
Partners
 
Partner
Partnership Revenue:
 
 
 
 
Natural gas, NGLs and crude oil sales
 
80
%
 
20
%
Preferred cash distribution (a)
 
100
%
 
%
Commodity price risk management gain (loss)
 
80
%
 
20
%
Sale of productive properties
 
80
%
 
20
%
Sale of equipment
 
%
 
100
%
Interest income
 
80
%
 
20
%
 
 
 
 
 
Partnership Operating Costs and Expenses:
 
 
 
 
Natural gas, NGLs and crude oil production and well
 
 
 
 
operations costs (b)
 
80
%
 
20
%
Depreciation, depletion and amortization expense
 
80
%
 
20
%
Accretion of asset retirement obligations
 
80
%
 
20
%
Direct costs - general and administrative (c)
 
80
%
 
20
%


(a)
To the extent that Investor Partners receive preferred cash distributions, the allocations for Investor Partners will be increased accordingly and the allocation for the Managing General Partner will likewise be decreased. See Performance Standard Obligation of Managing General Partner below.
(b)
Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
(c)
The Managing General Partner receives monthly reimbursement from this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this Partnership.

Performance Standard Obligation of Managing General Partner. The Agreement provides for the enhancement of investor cash distributions if this Partnership does not meet a performance standard defined in the Agreement during the first 10 years of operations, beginning 6 months after the funding of this Partnership. In general, if the average annual rate of return to the Investor Partners is less than 12.8% of their subscriptions, the allocation rate of cash distributions to Investor Partners will increase up to one-half of the Managing General Partner's interest until the average annual rate increases to 12.8%, with a corresponding decrease to Managing General Partner. The 12.8% rate of return is calculated by including the estimated benefit of 25% income tax savings on the investment in the first year in addition to the cash distributions made to the Investor Partners as a percentage of the investment, divided by the number of years since the closing of this Partnership less six months.

Beginning in November 2009 when the conditions of the obligation arose, and expiring upon the termination of Performance Standard Obligation provision in February 2013, this Partnership modified the allocation rate of all items of profit and loss and resulting cash available for distribution between Managing General Partner and the Investor Partners, pursuant to this provision of the Agreement. For the twelve months ended December 31, 2012 and 2011, distributions paid to the Managing General Partner were reduced and distributions to the Investor Partners were increased by $3,345 and $4,678, respectively, as a result of the Preferred Cash Distribution made under the terms of this provision. Accumulated Preferred Cash Distributions paid to the Investor Partners through December 31, 2012 were $69,722.

Unit Repurchase Provisions. Investor Partners may request that the Managing General Partner repurchase limited partnership units at any time beginning with the third anniversary of the first cash distribution of this Partnership. The repurchase price is set at a minimum of four times the most recent twelve months of cash distributions from production. In any calendar year, the Managing General Partner is conditionally obligated to purchase Investor Partner units aggregating up to 10% of the initial subscriptions, if requested by an individual investor partner, subject to PDC's financial ability to do so and upon receipt of opinions of counsel that the repurchase will not cause this Partnership to be treated as a “publicly traded partnership” or result in the termination of this Partnership for federal income tax purposes. If accepted, repurchase requests are fulfilled by the Managing General Partner on a first-come, first-serve basis.

Cash Distributions

The Agreement requires the Managing General Partner to distribute cash available for distribution no less frequently than quarterly. Except as modified under the Performance Standard Obligation provision, the Managing General Partner determines and distributes cash on a monthly basis, if funds are available for distribution. The Managing General Partner makes cash distributions of 80% to the Investor Partners and 20% to the Managing General Partner. Cash distributions began in March 2003. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:
 
 
Year ended December 31,
 
 
2012
 
2011
 
 
 
 
 
Cash distributions
 
$
35,297

 
$
45,056



Cash distributions decreased in 2012 compared to 2011, primarily due to a decrease in cash flows from operating activities during 2012, partially offset by a decrease in capital expenditures in 2012.
v2.4.0.6
Transactions with Managing General Partner
12 Months Ended
Dec. 31, 2012
Related Party Transactions [Abstract]  
Related Party Transactions Disclosure [Text Block]
TRANSACTIONS WITH MANAGING GENERAL PARTNER

The Managing General Partner transacts business on behalf of this Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received by the Managing General Partner on behalf of this Partnership are distributed to the Partners net of corresponding operating costs and other cash outflows incurred on behalf of this Partnership. The fair value of this Partnership's portion of open derivative instruments is recorded on the balance sheets under the captions “Due from Managing General Partner-derivatives” in the case of net unrealized gains and “Due to Managing General Partner-derivatives” in the case of net unrealized losses.

The following table presents transactions with the Managing General Partner reflected in the balance sheet line item “Due from (to) Managing General Partner-other, net” which remain undistributed or unsettled with this Partnership's investors as of the dates indicated:

    
 
December 31, 2012
 
December 31, 2011
Natural gas, NGLs and crude oil sales revenues
collected from this Partnership's third-party customers
$
20,841

 
$
57,606

Commodity price risk management, realized gain
14,367

 
9,620

Other (1)
(102,728
)
 
(165,585
)
Total Due to Managing General Partner-other, net
$
(67,520
)
 
$
(98,359
)

(1)
All other unsettled transactions, excluding derivative instruments, between this Partnership and the Managing General Partner. The majority of these are operating costs and general and administrative costs which have not been deducted from distributions.

Commencing with the 40th month of well operations, the Managing General Partner withholds from monthly Partnership cash available for distributions amounts to be used to fund statutorily-mandated well plugging, abandonment and environmental site restoration expenditures. A Partnership well may be sold or plugged, reclaimed and abandoned, with consent of all non-operators, when depleted or an evaluation is made that the well has become uneconomical to produce. Per-well plugging fees withheld during 2012 and 2011 were $50 per well each month the well produced. The total amount withheld from Partnership's cash available for distributions for the purposes of funding future Partnership obligations is recorded on the balance sheets in the long-term asset line captioned "Other assets."

The following table presents Partnership transactions, excluding derivative transactions which are more fully detailed in Note 4, Derivative Financial Instruments, with the Managing General Partner for the years ended December 31, 2012 and 2011. “Well operations and maintenance” and “Gathering, compression and processing fees” are included in the “Natural gas, NGLs and crude oil production costs” line item on the statements of operations.    
 
Year ended December 31,
 
2012
 
2011
 Well operations and maintenance (1)
$
239,151

 
$
203,042

 Gathering, compression and processing fees (2)
17,467

 
20,906

 Direct costs - general and administrative (3)
127,801

 
308,164

 Cash distributions (4)
5,751

 
6,681


(1) Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from this Partnership when the wells begin producing.
Well charges. The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of this Partnership, monthly well operating charges for operating and maintaining the wells during producing operations, which reflects a competitive field rate, and a monthly administration charge for Partnership activities.
Under the D&O Agreement, PDC provides all necessary labor, vehicles, supervision, management, accounting and overhead services for normal production operations, and may deduct from Partnership revenues a fixed monthly charge for these services. The charge for these operations and field supervision fees (referred to as “well tending fees”) for each producing well is based on competitive industry field rates which vary based on areas of operation. The well tending fees and administration fees may be adjusted annually to an amount equal to the rates initially established by the D&O Agreement multiplied by the then current average of the Oil and Gas Extraction Index and the Professional and Technical Services Index, as published by the United States Department of Labor, Bureau of Labor Statistics, provided that the charge may not exceed the rate which would be charged by the comparable operators in the area of operations. This average is commonly referred to as the Accounting Procedure Wage Index Adjustment which is published annually by the Council of Petroleum Accountants Societies. These rates are reflective of similar costs incurred by comparable operators in the production field. PDC, in certain circumstances, has and may in the future, provide equipment or supplies, perform salt water disposal services and other services for this Partnership at the lesser of cost or competitive prices in the area of operations.
The Managing General Partner as operator bills non-routine operations and administration costs to this Partnership at its cost. The Managing General Partner may not benefit by inter-positioning itself between this 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, or well tending, charges cover all normal and regularly recurring operating expenses for the production, delivery and sale of natural gas, NGLs and crude 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 this Partnership and government agencies.

The well supervision fees do not include costs and expenses related to:

the purchase or repairs of equipment, materials or third-party services;
the cost of compression and third-party gathering services, or gathering costs;
brine disposal; or
rebuilding of access roads.
These costs are charged at the invoice cost of the materials purchased or the third-party services performed.
Lease Operating Supplies and Maintenance Expense. The Managing General Partner may enter into other transactions with this Partnership for services, supplies and equipment during the production phase of this Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.
(2) Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural gas produced by this 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, this 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, this Partnership pays the gathering fee charged by the third-party gathering the natural gas.
(3) The Managing General Partner is reimbursed by this Partnership for all direct costs expended on this Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.
(4) Except as modified under the Performance Standard Obligation provision, the Agreement provides for the allocation of cash distributions 80% to the Investors Partners and 20% to the Managing General Partner. Cash distributions to the Managing General Partner for the twelve months ended December 31, 2012 and 2011 were reduced by $3,345 and $4,678, respectively, due to Preferred Cash Distribution made by the Managing General Partner to Investor Partners under the Performance Standard Obligation provision of the Agreement. The Investor Partner cash distributions during the years ended December 31, 2012 and 2011 include $2,037 and $2,347, respectively, related to equity cash distributions for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions and provisions of the Standard Performance Obligation, refer to Note 8, Partners’ Equity and Cash Distributions.
v2.4.0.6
Impairment of Capitalized Costs
12 Months Ended
Dec. 31, 2012
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]  
Impairment of natural gas and crude oil properties [Table Text Block]
IMPAIRMENT OF CAPITALIZED COSTS

In December 2012, this Partnership recognized an impairment charge of $1,078,355 associated with its Wattenberg Field proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on a discounted cash flow analysis.

In December 2011, this Partnership recognized an impairment charge of $328,097 associated with its Piceance Basin proved oil and natural gas properties. The assets were determined to be impaired as the estimated undiscounted future net cash flows were less than the carrying value of the assets. The fair value for determining the amount of the impairment charge was based on a discounted cash flow analysis. See Supplemental Natural Gas, NGLs and Crude Oil Information–Unaudited–Capitalized Costs and Costs Incurred in Natural Gas and Crude Oil Property Development Activities for additional information on impairment of capitalized costs.
v2.4.0.6
Subsequent Events (Notes)
12 Months Ended
Dec. 31, 2012
Subsequent Event [Line Items]  
Subsequent Events [Text Block]
SUBSEQUENT EVENT

On February 4, 2013, this Partnership's Managing General Partner, PDC, entered into a Purchase and Sale Agreement (“PSA”) with certain affiliates of Caerus Oil and Gas LLC (“Caerus”), pursuant to which this Partnership has agreed to sell to Caerus this Partnership's Piceance Basin oil and gas properties located in Garfield County, Colorado. The aggregate cash consideration of approximately $431,000 is subject to customary adjustments to the purchase price, including adjustments based on title and environmental due diligence to be conducted by Caerus and a 1% selling fee. The PSA does not include any of this Partnership's Wattenberg Field assets. Additionally, this Partnership has agreed to sell certain derivative instruments associated with the Piceance Basin to Caerus at fair market value. There can be no assurance that this transaction will close as planned.
v2.4.0.6
Supplemental Natural Gas, NGL and Crude Oil Information - Unaudited
12 Months Ended
Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
Oil and Gas Exploration and Production Industries Disclosures [Text Block]
Net Proved Reserves

This Partnership utilized the services of an independent petroleum engineer, Ryder Scott Company, L.P. ("Ryder Scott"), to estimate this Partnership's 2012 and 2011 natural gas, NGLs and crude oil reserves. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC.

Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. This 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 natural gas, NGLs and crude oil expected to be recovered from currently producing zones under the continuation of present operating methods. Proved undeveloped reserves are those reserves expected to be recovered from existing wells where a relatively major expenditure is required for additional reserve development. As of December 31, 2012, there are no proved undeveloped reserves for this Partnership.

This Partnership's estimated proved developed non-producing reserves consist entirely of reserves attributable to the Wattenberg Field's additional development. These additional development activities part of the Additional Development Plan, generally occur five to ten years after initial well drilling. The time frame for development activity is impacted by individual well decline curves as well as the plan to maximize the financial impact of the additional development.

The following table presents the prices used to estimate this Partnership's reserves, by commodity:

 
 
Price Used to Estimate Reserves (1)
As of December 31,
 
Crude Oil (per Bbl)
 
Natural Gas (per Mcf)
 
NGLs (per Bbl)
2012
 
$
87.32

 
$
2.18

 
$
28.27

2011
 
87.87

 
3.39

 
40.87



(1)
The prices used to estimate reserves have been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to this Partnership's year-end estimated proved reserves. Prices for each of the two years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of this Partnership's commodity derivatives.

The following table presents the changes in estimated quantities of this Partnership's reserves, all of which are located within the United States:
 
Natural Gas
 
NGLs
 
Crude Oil and Condensate
 
Natural Gas Equivalent
 
(MMcf)
 
(MBbl)
 
(MBbl)
 
(MMcfe)
Proved Reserves:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved reserves, January 1, 2011
1,079

 
18

 
65

 
1,577

Revisions of previous estimates and reclassifications
3

 
24

 
3

 
165

Production
(85
)
 
(1
)
 
(3
)
 
(109
)
Proved reserves, December 31, 2011
997

 
41

 
65

 
1,633

 
 
 
 
 
 
 
 
Revisions of previous estimates and reclassifications
(590
)
 
(25
)
 
(37
)
 
(962
)
Production
(71
)
 
(1
)
 
(2
)
 
(89
)
Proved reserves, December 31, 2012 (1)
336

 
15

 
26

 
582

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Proved Developed Reserves, as of:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2011
997

 
41

 
65

 
1,633

December 31, 2012
336

 
15

 
26

 
582

 
 
 
 
 
 
 
 

(1)
Includes estimated reserve data related to this Partnership's Piceance Basin assets, which are expected to be divested pursuant to a purchase and sale agreement entered into on February 4, 2013. See Note 11, Subsequent Event, to this Partnership's financial statements included elsewhere in this report for additional details related to the planned divestiture of this Partnership's Piceance Basin assets. As of December 31, 2012, total proved reserves related to this Partnership's Piceance Basin include 144 MMcf of natural gas and 1 MBbls of crude oil, for an aggregate of 150 MMcfe of natural gas equivalent.

2012 Activity. At December 31, 2012, this Partnership recorded a downward revision of its previous estimate of proved reserves by approximately 962 MMcfe. The revision includes downward revisions to previous estimates of 590 MMcf of natural gas, 25 MBbls of NGLs and 37 MBbls of crude oil. The downward revisions were the result of lower pricing and reduced asset performance. There were no proved undeveloped reserves developed in 2012. There were no proved undeveloped reserves attributable to this Partnership's assets as of December 31, 2012.

2011 Activity. At December 31, 2011, this Partnership recorded an upward revision of its previous estimate of proved reserves by approximately 165 MMcfe. The revision includes upward revisions to previous estimates of 3 MMcf of natural gas, 24 MBbls of NGLs and 3 MBbls of crude oil. The upward revision for NGLs was primarily due to a higher yield resulting from improved infrastructure as new processing plants were established in the Wattenberg Field area. Proved undeveloped reserves of 615 MMcfe were transferred to proved developed reserves in 2011 due to the reclassification of this Partnership's estimated Wattenberg refracture reserves as a result of the Managing General Partner's determination of the cost of a refracture becoming less significant as compared to the cost of drilling a new well. There were no proved undeveloped reserves developed in 2011.
  
Capitalized Costs and Costs Incurred in Natural Gas and Crude Oil Property Development Activities

Natural gas and crude oil development costs include costs incurred to gain access to and prepare development well locations for drilling, drill and equip developmental wells, complete additional production formations or recomplete existing production formations and provide facilities to extract, treat, gather and store natural gas and crude oil.

This Partnership is engaged solely in natural gas and crude oil activities, all of which are located in the continental United States. Drilling operations began upon funding in September 2002. This Partnership owns an undivided working interest in 14 gross (12.8 net) productive natural gas and crude oil wells. This Partnership owns 11 wells located in the Wattenberg Field within the Denver-Julesburg (“DJ”) Basin, north and east of Denver, Colorado and three wells located in the Piceance Basin, situated near the western border of Colorado.

Aggregate capitalized costs related to natural gas and crude oil development and production activities with applicable accumulated DD&A are presented below:
 
 As of December 31,
 
2012
 
2011
Leasehold costs
$
110,318

 
$
322,078

Development costs
3,057,339

 
7,452,367

Natural gas and crude oil properties, successful efforts method, at cost
3,167,657

 
7,774,445

Less: Accumulated DD&A
(2,270,162
)
 
(5,592,847
)
Natural gas and crude oil properties, net
$
897,495

 
$
2,181,598



Included in “Development costs” are the estimated costs associated with this Partnership's asset retirement obligations discussed in Note 6, Asset Retirement Obligations.

This Partnership, from time-to-time, invests in additional equipment which supports treatment, delivery and measurement of natural gas and crude oil or environmental protection. These amounts totaled approximately $3,000 and $40,000 for 2012 and 2011, respectively.

This Partnership recorded an impairment charge of$1,078,355 for the year ended December 31, 2012. Accordingly, this Partnership reduced "Natural gas and crude oil properties" by $4,609,745 and related "Accumulated depreciation, depletion and amortization" for those properties of $3,531,390 as of December 31, 2012. This Partnership also recorded an impairment charge of $328,097 for the year ended December 31, 2011. Accordingly, this Partnership reduced “Natural gas and crude oil properties” by $1,054,695 and related “Accumulated depreciation, depletion and amortization” for those properties of $726,598 as of December 31, 2011. See Note 10, Impairment of Capitalized Costs for additional disclosure related to this Partnership's proved property impairment.
v2.4.0.6
Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)
12 Months Ended
Dec. 31, 2012
Accounting Policies [Abstract]  
Use of Estimates, Policy [Policy Text Block]
The preparation of this Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires this Partnership to make estimates and assumptions that affect the amounts reported in this Partnership's financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to the financial statements include estimates of natural gas, natural gas liquids (“NGLs”) and crude oil sales revenue, proved reserves, future cash flows from natural gas and crude oil properties and valuation of derivative instruments
Basis of Accounting, Policy [Policy Text Block]

The financial statements include only those assets, liabilities and results of operations of the partners which relate to the business of this Partnership.
Cash and Cash Equivalents, Policy [Policy Text Block]
This Partnership considers all highly liquid investments with original maturities of three months or less to be cash equivalents. This Partnership maintains substantially all of its cash and cash equivalents in a bank account at one financial institution
Receivables, Policy [Policy Text Block]
accounts receivable are from purchasers of natural gas, NGLs and crude oil. This Partnership sells substantially all of its natural gas, NGLs and crude oil to customers who purchase natural gas, NGLs and crude oil from other partnerships managed by this Partnership's Managing General Partner. The Managing General Partner periodically reviews accounts receivable for credit risks resulting from changes in the financial condition of its customers
Inventory, Policy [Policy Text Block]
Inventory consists of crude oil, stated at the lower of cost to produce or market
Derivatives, Policy [Policy Text Block]
All derivative assets and liabilities are recorded on the balance sheets at fair value. PDC, as Managing General Partner, has elected not to designate any of this Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of this Partnership's derivative instruments are recorded in this Partnership's statements of operations and this Partnership's net income is subject to greater volatility than if this Partnership's derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to this Partnership's natural gas and crude oil sales and the realized gain or loss upon the settlement of these instruments are recorded in the line captioned, “Commodity price risk management gain, net.” As positions designated to this Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to this Partnership and net realized losses are deducted from this Partnership's cash distributions generated from production. This Partnership bears its proportionate share of counterparty risk.

The validation of the derivative instrument's fair value is performed by the Managing General Partner. While the Managing General Partner uses common industry practices to develop this Partnership's valuation techniques, changes in this Partnership's pricing methodologies or the underlying assumptions could result in significantly different fair values
Oil and Gas Properties Policy [Policy Text Block]
This Partnership accounts for its natural gas and crude oil properties under the successful efforts method of accounting. Costs of proved developed producing properties, and developmental dry hole costs are capitalized and depreciated or depleted by the units-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the units-of-production method based on estimated proved reserves. This Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator this Partnership's estimated quarter-end reserves, adjusted to add back current period production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the statement of operations as a gain or loss. Upon the sale of individual wells, the proceeds are credited to accumulated DD&A. See Supplemental Natural Gas, NGLs and Crude Oil Information - Unaudited, Net Proved Reserves, included at the end of these financial statements and accompanying notes elsewhere in this report for additional information regarding this Partnership's reserve reporting. In accordance with the Agreement, all capital contributed to this Partnership, after deducting syndication costs and a one-time management fee was, used solely for the drilling of natural gas and crude oil wells. This Partnership does not maintain an inventory of undrilled leases.

Proved Reserves. Partnership estimates of proved reserves are based on those quantities of natural gas, NGLs and crude oil which, by analysis of geoscience and engineering data, are estimated with reasonable certainty to be economically producible in the future from known reservoirs under existing conditions, operating methods and government regulations. Annually, the Managing General Partner engages independent petroleum engineers to prepare a reserve and economic evaluation of this Partnership's properties on a well-by-well basis as of December 31. Additionally, this Partnership adjusts reserves for major well rework or abandonment during the year, as needed. The process of estimating and evaluating natural gas, NGLs and crude oil 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 represent this Partnership's 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 this Partnership's DD&A expense, a change in this Partnership's estimated reserves could have an effect on this Partnership's net income or loss.

Property, Plant and Equipment, Impairment [Policy Text Block]
This Partnership assesses its producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs, or carrying value, 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 the commodities to be sold. The estimates of future prices may differ from current market prices of natural gas and crude oil. Certain events, including but not limited to, downward revisions in estimates to this Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of this Partnership's proved natural gas and crude oil properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairment charges are included in the statement of operations line item impairment of natural gas and crude oil properties, with a corresponding reduction to natural gas and crude oil properties and accumulated depreciation, depletion and amortization line items on the balance sheet.
Production Tax Liability, Policy [Policy Text Block]
Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which this Partnership produces natural gas, NGLs and crude oil. This Partnership's share of these taxes is expensed to the account “Natural gas, NGLs and crude oil production costs.” This Partnership's production taxes payable are included in the caption “Accounts payable and accrued expenses” on this Partnership's balance sheets.
Asset Retirement Obligations, Policy [Policy Text Block]
This Partnership accounts for asset retirement obligations by recording the fair value of Partnership well plugging and abandonment obligations when incurred, which is at the time the well is spud. Upon initial recognition of an asset retirement obligation, this Partnership increases the carrying amount of the long-lived asset by the same amount as the liability. Over time, the liabilities are accreted for the change in 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, revisions to estimated retirement costs and changes in the estimated timing of settling retirement obligations.
Revenue Recognition, Policy [Policy Text Block]
Natural gas, NGLs and crude oil revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. This Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of this Partnership's sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells this Partnership's natural gas at the wellhead and recognizes revenues based on the wellhead sales price since transportation and processing costs downstream of the wellhead are incurred by this Partnership's purchasers and reflected in the wellhead price. The majority of this Partnership's natural gas, NGLs and crude oil 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 contract 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 and quality of the natural gas.
Accounting Standards Recently Adopted [Policy Text Block]
Fair Value Measurement

On May 12, 2011, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards and U.S. GAAP. The changes expand existing disclosure requirements for fair value measurements categorized in Level 3 by requiring (1) a quantitative disclosure of the unobservable inputs and assumptions used in the measurement, (2) a description of the valuation processes in place and (3) a narrative description of the sensitivity of the fair value to changes in unobservable inputs and the interrelationships between those inputs. In addition, the changes require the categorization by level in the fair value hierarchy of items that are not measured at fair value in the statement of financial position whose fair value must be disclosed. These changes are to be applied prospectively and were effective for public entities during interim and annual periods beginning after December 15, 2011. Early application was not permitted. With the exception of the disclosure requirements, the adoption of these changes did not have a significant impact on this Partnership's financial statements.
v2.4.0.6
Fair Value of Financial Instruments Fair Value Measurements and Disclosures (Tables)
12 Months Ended
Dec. 31, 2012
Fair Value Disclosures [Abstract]  
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]
The following table presents, for each applicable level within the fair value hierarchy, this Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis:

 
Balance Sheet
 
December 31, 2012
 
December 31, 2011
 
Line Item
 
 Level 2
 
 Level 3
 
 Total
 
 Level 2
 
 Level 3
 
 Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Assets:
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Commodity-based derivatives
Due from Managing General Partner-derivatives
 
$
180,165

 
$

 
$
180,165

 
$
192,906

 
$
8,269

 
$
201,175

Non-Current
 
 
 
 
 
 
 
 
 
 
 
 
 
 Commodity-based derivatives
Due from Managing General Partner-derivatives
 

 

 

 
157,086

 

 
157,086

 Total assets
 
 
180,165

 

 
180,165

 
349,992

 
8,269

 
358,261

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 
 
Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 
81,917

 

 
81,917

 
87,900

 

 
87,900

Non-Current
 
 
 
 
 
 
 
 
 
 
 
 
 
Basis protection derivative contracts
Due to Managing General Partner-derivatives
 

 

 

 
77,860

 

 
77,860

 Total liabilities
 
 
81,917

 

 
81,917

 
165,760

 

 
165,760

 Net asset
 
 
$
98,248

 
$

 
$
98,248

 
$
184,232

 
$
8,269

 
$
192,501

Fair Value Assets and Liabilities Unobservable Input Reconciliation [Table Text Block]
The following table presents a reconciliation of this Partnership's Level 3 measured at fair value:
 
Year ended
 
December 31, 2012
 
December 31, 2011
 Fair value, net asset, beginning of period
$
8,269

 
$
12,277

 Changes in fair value included in statement of operations line item:
 
 
 
 Commodity price risk management gain, net
637

 
6,256

 Settlements
(8,906
)
 
(10,264
)
 Fair value, net asset, end of period
$

 
$
8,269

 
 
 
 
Change in unrealized gain (loss) relating to assets (liabilities) still held as of
 

 
 
December 31, 2012 and 2011, respectively, included in statement of operations line item:
 
 
 
 Commodity price risk management gain, net
$

 
$
4,768

v2.4.0.6
Derivative Financial Instruments Derivative Financial Instruments (Tables)
12 Months Ended
Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]
The following tables present the impact of this Partnership's derivative instruments on this Partnership's accompanying statements of operations:
 
 
Year ended December 31,
 
 
2012
 
2011
Statement of operations line item:
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains For the Current Period
 
Total
 
Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized
 
Realized and Unrealized Gains For the Current Period
 
Total
Commodity price risk management gain, net
 
 
 
 
 
 
 
 
 
 
 
 
Realized gains
 
$
113,274

 
$
24,277

 
$
137,551

 
$
18,864

 
$
15,350

 
$
34,214

Unrealized gains (losses)
 
(113,274
)
 
19,021

 
(94,253
)
 
(18,864
)
 
146,688

 
127,824

Total
$

 
$
43,298

 
$
43,298

 
$

 
$
162,038

 
$
162,038

v2.4.0.6
Concentration of Risk Concentration of Risk (Tables)
12 Months Ended
Dec. 31, 2012
Concentration Risk - Revenue  
Individual Customers Constituting 10% or more of Total Revenue [Table Text Block]
Major Customers. The following table presents the individual customers constituting 10% or more of total revenues:
 
 
Year ended December 31,
Major Customer
 
2012
 
2011
Suncor Energy Marketing, Inc.
 
42%
 
44%
WPX Energy Rocky Mountain, LLC
 
32%
 
30%
DCP Midstream, LP
 
17%
 
23%
v2.4.0.6
Asset Retirement Obligations Asset Retirement Obligations (Tables)
12 Months Ended
Dec. 31, 2012
Asset Retirement Obligation Disclosure [Abstract]  
Schedule of Change in Asset Retirement Obligation [Table Text Block]
The following table presents the changes in carrying amounts of the asset retirement obligations associated with this Partnership's working interest in natural gas and crude oil properties:

 
Year ended December 31,
 
2012
 
2011
 
 
 
 
Balance at beginning of year
$
208,823

 
$
154,650

Revisions in estimated cash flows

 
44,358

Accretion expense
14,442

 
9,815

Balance at end of year
$
223,265

 
$
208,823

v2.4.0.6
Partners' Equity and Cash Distributions (Tables)
12 Months Ended
Dec. 31, 2012
Allocation of Partners' Interest  
Allocation of Partner Interest [Table Text Block]
Allocation of Partners' Interest. The following table presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of this Partnership:
 
 
 
 
Managing
 
 
Investor
 
General
 
 
Partners
 
Partner
Partnership Revenue:
 
 
 
 
Natural gas, NGLs and crude oil sales
 
80
%
 
20
%
Preferred cash distribution (a)
 
100
%
 
%
Commodity price risk management gain (loss)
 
80
%
 
20
%
Sale of productive properties
 
80
%
 
20
%
Sale of equipment
 
%
 
100
%
Interest income
 
80
%
 
20
%
 
 
 
 
 
Partnership Operating Costs and Expenses:
 
 
 
 
Natural gas, NGLs and crude oil production and well
 
 
 
 
operations costs (b)
 
80
%
 
20
%
Depreciation, depletion and amortization expense
 
80
%
 
20
%
Accretion of asset retirement obligations
 
80
%
 
20
%
Direct costs - general and administrative (c)
 
80
%
 
20
%


(a)
To the extent that Investor Partners receive preferred cash distributions, the allocations for Investor Partners will be increased accordingly and the allocation for the Managing General Partner will likewise be decreased. See Performance Standard Obligation of Managing General Partner below.
(b)
Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
(c)
The Managing General Partner receives monthly reimbursement from this Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of this Partnership.
Cash Distributions[Table Text Block]
The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:
 
 
Year ended December 31,