v2.4.0.6
Document and Entity Information Document (USD $)
12 Months Ended
Dec. 31, 2011
Feb. 29, 2012
Jun. 30, 2011
Entity Information [Line Items]      
Entity Registrant Name Rockies Region 2007 LP    
Entity Central Index Key 0001407805    
Current Fiscal Year End Date --12-31    
Entity Filer Category Smaller Reporting Company    
Document Type 10-K    
Document Period End Date Dec. 31, 2011    
Document Fiscal Year Focus 2011    
Document Fiscal Period Focus FY    
Amendement Flag false    
Entity Common Stock, Share Outstanding   0  
Entity Well-known Seasoned Issuer No    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Public Float     $ 0
v2.4.0.6
Balance Sheets - December 31,2011 and 2010 Statement (USD $)
Dec. 31, 2011
Dec. 31, 2010
Current assets:    
Cash and cash equivalents $ 2,690,377 $ 690,377
Accounts receivable 767,950 1,175,972
Crude oil inventory 47,247 59,031
Due from Managing General Partner-derivatives 5,067,966 3,178,313
Due from Managing General Partner-other, net 411,571 534,115
Total current assets 8,985,111 5,637,808
Natural gas and crude oil properties, successful efforts method, at cost 80,260,368 79,934,322
Less: Accumulated depreciation, depletion and amortization (35,059,637) (29,699,641)
Natural gas and crude oil properties, net 45,200,731 50,234,681
Due from Managing General Partner-derivatives 3,844,431 4,689,041
Total noncurrent assets 49,045,162 54,923,722
Total Assets 58,030,273 60,561,530
Current liabilities:    
Accounts payable and accrued expenses 95,529 136,704
Due to Managing General Partner-derivatives 2,217,809 2,580,843
Total current liabilities 2,313,338 2,717,547
Due to Managing General Partner-derivatives 1,905,253 3,556,891
Asset retirement obligations 1,031,186 727,952
Total liabilities 5,249,777 7,002,390
Commitments and contingent liabilities      
Partners' equity:    
Managing General Partner 14,334,835 14,622,934
Limited Partners - 4,470 units issued and outstanding 38,445,661 38,936,206
Total Partners' equity 52,780,496 53,559,140
Total Liabilities and Partners' Equity $ 58,030,273 $ 60,561,530
v2.4.0.6
Condensed Balance Sheet Parenthetical
Dec. 31, 2011
Dec. 31, 2010
Units of Limited Partnership Interest Issued 4,470.00 4,470.00
Units of Limited Partnership Interest Outstanding 4,470.00 4,470.00
v2.4.0.6
Statements of Operations - For the Years Ended December 31, 2011 and 2010 Statement (USD $)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Revenues:    
Natural gas, NGLs and crude oil sales $ 10,560,194 $ 14,489,015
Commodity price risk management gain, net 4,064,746 8,150,531
Total revenues 14,624,940 22,639,546
Operating costs and expenses:    
Natural gas, NGLs and crude oil production costs 4,368,553 5,061,490
Direct costs - general and administrative 213,327 200,907
Depreciation, depletion and amortization 5,359,996 9,456,143
Accretion of asset retirement obligations 52,555 47,304
Loss on impairment of natural gas and crude oil properties 0 27,687,418
Total operating costs and expenses 9,994,431 42,453,262
Income (loss) from operations 4,630,509 (19,813,716)
Interest income 889 0
Net income (loss) 4,631,398 (19,813,716)
Net income (loss) allocated to partners 4,631,398 (19,813,716)
Less: Managing General Partner interest in net income (loss) 1,713,617 (7,331,075)
Net income (loss) allocated to Investor Partners $ 2,917,781 $ (12,482,641)
Net income (loss) per Investor Partner unit $ 653 $ (2,793)
Investor Partner units outstanding 4,470.00 4,470.00
v2.4.0.6
Statement of Partners' Equity - For the Years Ended December 31, 2011 and 2010 (USD $)
Total
Investor Partners
Managing General Partner
Balance at Dec. 31, 2009 $ 87,728,748 $ 60,463,059 $ 27,265,689
Increase (Decrease) in Partners' Capital [Roll Forward]      
Distributions to partners (14,355,892) (9,044,212) (5,311,680)
Net income (loss) (19,813,716) (12,482,641) (7,331,075)
Balance at Dec. 31, 2010 53,559,140 38,936,206 14,622,934
Increase (Decrease) in Partners' Capital [Roll Forward]      
Distributions to partners (5,410,042) (3,408,326) (2,001,716)
Net income (loss) 4,631,398 2,917,781 1,713,617
Balance at Dec. 31, 2011 $ 52,780,496 $ 38,445,661 $ 14,334,835
v2.4.0.6
Statements of Cash Flows For the Years Ended December 31, 2011 and 2010 Statement (USD $)
12 Months Ended
Dec. 31, 2011
Dec. 31, 2010
Cash flows from operating activities:    
Net income (loss) $ 4,631,398 $ (19,813,716)
Adjustments to net income (loss) to reconcile to net cash provided by operating activities:    
Depreciation, depletion and amortization 5,359,996 9,456,143
Accretion of asset retirement obligations 52,555 47,304
Unrealized gain on derivative transactions (3,059,715) (4,681,115)
Loss on impairment of natural gas and crude oil properties 0 27,687,418
Changes in operating assets and liabilities:    
Decrease in accounts receivable 408,022 366,833
Decrease (increase) in crude oil inventory 11,784 (24,077)
Decrease in accounts payable and accrued expenses (41,175) (57,085)
Decrease in Due from Managing General Partner - other, net 122,544 2,130,851
Net cash provided by operating activities 7,485,409 15,112,556
Cash flows from investing activities:    
Capital expenditures for natural gas and crude oil properties (75,367) (70,516)
Net cash used in investing activities (75,367) (70,516)
Cash flows from financing activities:    
Distributions to partners (5,410,042) (14,355,892)
Net cash used in financing activities (5,410,042) (14,355,892)
Net increase in cash and cash equivalents 2,000,000 686,148
Cash and cash equivalents, beginning of period 690,377 4,229
Cash and cash equivalents, end of period 2,690,377 690,377
Supplemental disclosure of non-cash activity    
Change in asset retirement obligation, with corresponding increase to natural gas and crude oil properties $ 250,679 $ 0
v2.4.0.6
General
12 Months Ended
Dec. 31, 2011
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]
GENERAL

Rockies Region 2007 Limited Partnership (the “Partnership” or the “Registrant”) was organized 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, the Partnership entered into a Drilling and Operating Agreement (“D&O Agreement”) with the Managing General Partner which authorizes Petroleum Development Corporation (“PDC”), which conducts business under the name PDC Energy, to conduct and manage the 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 the Partnership and initiates and completes substantially all Partnership transactions.

As of December 31, 2011, there were 1,793 Investor Partners. PDC is the designated Managing General Partner of the Partnership and owns a 37% Managing General Partner ownership in the Partnership. According to the terms of the Limited Partnership Agreement, revenues, costs and cash distributions of the Partnership are allocated 63% to the limited partners (“Investor Partners”), which are shared pro rata based upon the number of units in the Partnership, and 37% to the Managing General Partner. Through December 31, 2011, the Managing General Partner has repurchased 5.5 units of Partnership interests from Investor Partners at an average price of $4,577 per unit. As of December 31, 2011, the Managing General Partner owns 37.08% of the Partnership.

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.

Certain reclassifications have been made to the prior period disclosures to conform to the current year presentation, specifically related to the fair value level classification of certain derivative instruments. The reclassification had no impact on the Partnership's previously reported financial position, cash flows, net income or partners' equity. See Note 3, Fair Value Measurements and Disclosures, for additional information regarding the fair value classification of the Partnership's derivative instruments.
v2.4.0.6
Summary of Significant Accounting Policies
12 Months Ended
Dec. 31, 2011
Accounting Policies [Abstract]  
Significant Accounting Policies [Text Block]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Management's Estimates

The preparation of the Partnership's financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires the Partnership to make estimates and assumptions that affect the amounts reported in the 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 (“NGL” or “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 the Partnership.

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 insured by Federal Deposit Insurance Corporation, or FDIC, up to $250,000 through December 31, 2013. The Partnership has not experienced losses in any such accounts to date and limits the 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. The Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The 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 the 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 was deemed necessary at December 31, 2011 or 2010.
Commitments. As Managing General Partner, PDC maintains performance bonds in the form of certificates of deposit for plugging, reclaiming and abandoning of the 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, the 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. The 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 the Partnership's derivative instruments as hedges. Accordingly, changes in the fair value of the Partnership's derivative instruments are recorded in the Partnership's statements of operations and the Partnership's net income is subject to greater volatility than if the Partnership's derivative instruments qualified for hedge accounting. Changes in the fair value of derivative instruments related to the 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 the Partnership settle, the realized gains and losses are netted for distribution. Net realized gains are paid to the Partnership and net realized losses are deducted from the Partnership's cash distributions generated from production. The Partnership bears its designated share of counterparty risk.

The validation of a contract's fair value is performed by the Managing General Partner. While the Managing General Partner uses common industry practices to develop the Partnership's valuation techniques, changes in the Partnership's pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value Measurements and Disclosures and Note 4, Derivative Financial Instruments, for a discussion of the Partnership's derivative fair value measurements and a summary fair value table of open positions as of December 31, 2011 and 2010.

Natural Gas and Crude Oil Properties. The Partnership accounts for its natural gas and crude oil properties (the “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 unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. The Partnership calculates quarterly depreciation, depletion and amortization ("DD&A") expense by using as the denominator the 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, NGL and Crude Oil Information - Unaudited, Net Proved 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 was used solely for the drilling of natural gas and crude oil wells. The 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 the Partnership's properties on a well-by-well basis as of December 31. Additionally, the 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 the 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 the Partnership's DD&A expense, a change in the Partnership's estimated reserves could have an effect on the Partnership's net income.


Proved Property Impairment. The Partnership assesses its producing natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The estimates of future prices may differ from current market prices of natural gas, NGLs and crude oil. Certain events, including but not limited to, downward revisions in estimates to the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership's 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, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows are determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. Due to the availability of new reserve information, the Partnership reviewed its proved natural gas and crude oil properties for impairment at December 31, 2011 and 2010. See Note 10, Impairment of Capitalized Costs for additional disclosure related to the Partnership's proved property impairment.

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 the Partnership produces natural gas, NGLs and crude oil. The Partnership's share of these taxes is expensed to the account “Natural gas, NGLs and crude oil production costs.” The Partnership's production taxes payable are included in the caption “Accounts payable and accrued expenses” on the Partnership's balance sheets.

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.

Asset Retirement Obligations. The 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 spudded. 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 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 the 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. The Partnership currently uses the “net-back” method of accounting for transportation and processing arrangements of the Partnership's sales when the transportation and/or processing is provided by or through the purchaser. Under these arrangements, the Managing General Partner sells the 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 the Partnership's purchasers and reflected in the wellhead price. The majority of the 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, quality of natural gas and prevailing supply and demand conditions.

Recent Accounting Standards.

The following standard was recently adopted:

Fair Value Measurements and Disclosures. In January 2010, the Financial Accounting Standards Board ("FASB") issued changes related to fair value measurements requiring gross presentation of activities within the Level 3 roll forward, whereby entities must present separately information about purchases, sales, issuances and settlements. These changes were effective for the Partnership's financial statements issued for annual reporting periods, and for interim reporting periods within the year, beginning after December 15, 2010. The adoption of this change did not have a material impact on the Partnership's financial statements.



The following standard was recently issued:

Fair Value Measurement. On May 12, 2011, the FASB issued changes related to fair value measurement. The changes represent the converged guidance of the FASB and the International Accounting Standards Board ("IASB") (collectively the "Boards") on fair value measurement. Many of the changes eliminate unnecessary wording differences between International Financial Reporting Standards ("IFRS") 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 also 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 are effective for public entities during interim and annual periods beginning after December 15, 2011. Early application is not permitted. With the exception of the disclosure requirements, the adoption of these changes is not expected to have a significant impact on the Partnership's financial statements.
v2.4.0.6
Fair Value Measurements and Disclosures
12 Months Ended
Dec. 31, 2011
Fair Value Disclosures [Abstract]  
Fair Value Disclosures [Text Block]
FAIR VALUE MEASUREMENTS AND DISCLOSURES

Derivative Financial Instruments

Determination of fair value. The Partnership's fair value measurements are estimated pursuant to a fair value hierarchy that requires the 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) 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. Includes the Partnership's fixed-price swaps and basis swaps.

Level 3 - Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Includes the Partnership's natural gas collars.

Derivative Financial Instruments. The Managing General Partner measures the fair value of the 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 (1) the review of counterparty statements and other supporting documentation, (2) the determination that the source of the inputs are valid, (3) the 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. 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 major lenders in the Managing General Partner's corporate credit facility agreement, 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 impact of the risk of nonperformance of the Managing General Partner's counterparties on the fair value of the Partnership's derivative instruments is insignificant.

The following table presents, for each hierarchy level, the Partnership's derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis.

 
December 31, 2011
 
December 31, 2010 (a)
 
 Level 2
 
 Level 3
 
 Total
 
 Level 2
 
 Level 3
 
 Total
 
 
 
 
 
 
 
 
 
 
 
 
 Assets:
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives
$
8,675,631

 
$
236,766

 
$
8,912,397

 
$
7,511,512

 
$
355,842

 
$
7,867,354

 Total assets
8,675,631

 
236,766

 
8,912,397

 
7,511,512

 
355,842

 
7,867,354

 
 
 
 
 
 
 
 
 
 
 
 
 Liabilities:
 
 
 
 
 
 
 
 
 
 
 
 Commodity based derivatives

 

 

 
618,004

 

 
618,004

 Basis protection derivative contracts
4,123,062

 

 
4,123,062

 
5,519,730

 

 
5,519,730

 Total liabilities
4,123,062

 

 
4,123,062

 
6,137,734

 

 
6,137,734

 
 
 
 
 
 
 
 
 
 
 
 
 Net asset
$
4,552,569

 
$
236,766

 
$
4,789,335

 
$
1,373,778

 
$
355,842

 
$
1,729,620

 
 
 
 
 
 
 
 
 
 
 
 

(a) The Partnership reclassified its NYMEX-based natural gas fixed-price swaps from Level 1 to Level 2 (decreasing the previously reported net asset in Level 1 by $7.5 million) and CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability in Level 3 by $6.1 million). The amounts presented reflect these reclassifications and conform to current period presentation.


The following table presents a reconciliation of the Partnership's Level 3 fair value measurements.
 
December 31,
 
2011
 
2010 (1)
 Fair value, net asset, beginning of year
$
355,842

 
$
739,017

 Changes in fair value included in statement of operations line item:
 
 
 
 Commodity price risk management, net
179,202

 
641,990

 Settlements
(298,278
)
 
(1,025,165
)
 Fair value, net asset, end of year
$
236,766

 
$
355,842

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

 
 
December 31, 2011 and 2010, respectively, included in statement of operations line item:
 
 
 
 Commodity price risk management, net
$
136,607

 
$
324,491


(1) The Partnership reclassified its CIG-based basis swaps and crude oil fixed-price swaps from Level 3 to Level 2 (decreasing the previously reported net liability at the beginning of the period by $5.3 million). The amounts presented reflect these reclassifications and conform to current period presentation.

See Note 4, Derivative Financial Instruments, for additional disclosure related to the Partnership's derivative financial instruments.

Non-Derivative Financial Assets and Liabilities

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

See Note 2, Natural Gas and Crude Oil Properties and Asset Retirement Obligations for a discussion of how we determined fair value for these assets and liabilities.
v2.4.0.6
Derivative Financial Instruments
12 Months Ended
Dec. 31, 2011
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Derivative Instruments and Hedging Activities Disclosure [Text Block]
DERIVATIVE FINANCIAL INSTRUMENTS

The Partnership's results of operations and operating cash flows are affected by changes in market prices for natural gas and crude oil. To manage a portion of the Partnership's exposure to price volatility from producing natural gas and crude oil, the Managing General Partner utilizes an economic hedging strategy for the Partnership's natural gas and crude oil sales, in which PDC, as Managing General Partner, enters into derivative contracts on behalf of the Partnership to protect against price declines in future periods. While the Managing General Partner structures these derivatives to reduce the Partnership's exposure to changes in price associated with the derivative commodities, they also limit the benefit the Partnership might otherwise have received from price increases in the physical market. The Managing General Partner believes the Partnership's derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2011, the Partnership had derivative instruments in place for the majority of its anticipated production through 2013 for a total of 2,640,855 MMbtu of natural gas. 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, 2011, the Partnership's derivative instruments were comprised of commodity collars, commodity fixed-price swaps and basis protection swaps.

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

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.

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 table presents the location and fair value amounts of the Partnership's derivative instruments on the accompanying balance sheets.
 
 
 
 
 
Fair Value
 
 
 
 
 
December 31,
 
December 31,
Derivative instruments not designated as hedge(1):
 
Balance Sheet Line Item
 
2011
 
2010
Derivative Assets:
Current
 
 
 
 
 
 
 
Commodity contracts
 
Due from Managing General Partner-derivatives
 
$
5,067,966

 
$
3,178,313

 
Non Current
 
 
 
 
 
 
 
Commodity contracts
 
Due from Managing General Partner-derivatives
 
3,844,431

 
4,689,041

Total Derivative Assets
 
 
 
 
8,912,397

 
7,867,354

 
 
 
 
 
 
 
 
Derivative Liabilities:
Current
 
 
 
 

 
 

 
Commodity contracts
 
Due to Managing General Partner-derivatives
 

 
618,004

 
Basis protection contracts
 
Due to Managing General Partner-derivatives
 
2,217,809

 
1,962,839

 
Non Current
 
 
 
 
 
 
 
Basis protection contracts
 
Due to Managing General Partner-derivatives
 
1,905,253

 
3,556,891

Total Derivative Liabilities
 
 
 
4,123,062

 
6,137,734

 
 
 
 
 
 
 
 
Net fair value of derivative instruments - asset
 
 
 
$
4,789,335

 
$
1,729,620

 
 
 
 
 
 
 
 

(1)As of December 31, 2011 and December 31, 2010, none of the Partnership's derivative instruments were designated as hedges.

The following table presents the impact of the Partnership's derivative instruments on the Partnership's accompanying statements of operations.
 
 
Year Ended December 31,
 
 
2011
 
2010
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
 
$
597,469

 
$
407,562

 
$
1,005,031

 
$
519,880

 
$
2,949,536

 
$
3,469,416

Unrealized gains (losses)
 
(597,469
)
 
3,657,184

 
3,059,715

 
(519,880
)
 
5,200,995

 
4,681,115

Total commodity price risk management gain, net
$

 
$
4,064,746

 
$
4,064,746

 
$

 
$
8,150,531

 
$
8,150,531

v2.4.0.6
Concentration of Risk
12 Months Ended
Dec. 31, 2011
Concentration Risks, Types, No Concentration Percentage [Abstract]  
Concentration Risk Disclosure [Text Block]
CONCENTRATION OF RISK

Accounts Receivable. The Partnership's accounts receivable are from purchasers of natural gas, NGLs and crude oil production. The 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 the Partnership's Managing General Partner. Inherent to the Partnership's industry is the concentration of natural gas, NGL and crude oil 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 and financial conditions, commodity prices or other conditions.

As of December 31, 2011 and 2010, the 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 the 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 the Partnership's Managing General Partner have experienced significant losses from uncollectible accounts receivable. The Partnership did not incur any losses on accounts receivable for the years ended December 31, 2011 and 2010.

Major Customers. The following table presents the individual customers constituting 10% or more of total revenues .

 
 
Year ended December 31,
Major Customer
 
2011
 
2010
 
 
 
 
 
DCP Midstream LP (“DCP”)
 
13%
 
14%
Williams Production RMT (“Williams”)
 
41%
 
44%
Suncor Energy (USA) Inc. (“Suncor”)
 
44%
 
40%

Derivative Counterparties. The Managing General Partner makes use of over-the-counter derivative instruments that enable the Partnership to manage a portion of its exposure to price volatility from producing natural gas and crude oil. These arrangements expose the Partnership to the credit risk of nonperformance by the counterparties. The Managing General Partner primarily uses financial institutions, who are also major lenders in the Managing General Partner's credit facility agreement, 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 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. Based on this evaluation, the Managing General Partner has determined that the impact of the risk of nonperformance of the counterparties on the fair value of the Partnership's derivative instruments was not significant.
v2.4.0.6
Asset Retirement Obligations Level 1 (Notes)
12 Months Ended
Dec. 31, 2011
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 the Partnership's working interest in natural gas and crude oil properties.

 
Year Ended December 31,
 
2011
 
2010
 
 
 
 
Balance at beginning of year
$
727,952

 
$
680,648

Revisions in estimated cash flows
250,679

 

Accretion expense
52,555

 
47,304

Balance at end of year
$
1,031,186

 
$
727,952


In 2011, the Managing General Partner revised its assumptions related to the cash outlay expected to be incurred to plug the Partnership's uneconomic wells.  The revision in the asset retirement obligation did not have an immediate effect in the current year 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, 2011
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Disclosure [Text Block]
COMMITMENTS AND CONTINGENCIES

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

Environmental. Due to the nature of the oil and gas industry, the 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 the Partnership's environmental risk profile. Liabilities are accrued when environmental remediation efforts are probable and the costs can be reasonably estimated. During the twelve months ended December 31, 2011, there were no new material environmental remediation projects identified by the Managing General Partner for the Partnership. As of December 31, 2011, the Partnership had accrued environmental remediation liabilities for the Partnership's Piceance Basin wells, in addition to one well in the Wattenberg Field, of approximately $18,000, which is included in line item captioned “Accounts payable and accrued expenses” on the balance sheet. As of December 31, 2010, the Partnership had accrued environmental remediation liabilities for the Partnership's Piceance Basin wells in the amount of approximately $5,000, which is included in line item captioned “Accounts payable and accrued expenses” on the balance sheet. The Managing General Partner is not currently aware of any environmental claims existing as of December 31, 2011, which have not been provided for or would otherwise have a material impact on the 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 the Partnership's properties.
v2.4.0.6
Partners' Equity and Cash Distributions
12 Months Ended
Dec. 31, 2011
Partners' Capital Account, Distributions [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 the Partnership. No public market exists or will develop for the units. While units of the Partnership are transferable, assignability of the units is limited, requiring the consent of the Managing General Partner. Further, individual investor partners may request that the Managing General Partner repurchase units pursuant to the Unit Repurchase Program.

Allocation of Partners' Interest. The table below presents the participation of the Investor Partners and the Managing General Partner in the revenues and costs of the Partnership.
 
 
 
 
Managing
 
 
Investor
 
General
 
 
Partners
 
Partner
Partnership Revenue:
 
 
 
 
Natural gas, NGLs and crude oil sales
 
63
%
 
37
%
Commodity price risk management gain (loss)
 
63
%
 
37
%
Sale of productive properties
 
63
%
 
37
%
Sale of equipment
 
63
%
 
37
%
Interest income
 
63
%
 
37
%
 
 
 
 
 
Partnership Operating Costs and Expenses:
 
 
 
 
Natural gas, NGLs and crude oil production and well
 
 
 
 
operations costs (a)
 
63
%
 
37
%
Depreciation, depletion and amortization expense
 
63
%
 
37
%
Accretion of asset retirement obligations
 
63
%
 
37
%
Direct costs - general and administrative (b)
 
63
%
 
37
%

(a)
Represents operating costs incurred after the completion of productive wells, including monthly per-well charges paid to the Managing General Partner.
(b)
The Managing General Partner receives monthly reimbursement from the Partnership for direct costs - general and administrative incurred by the Managing General Partner on behalf of the Partnership.

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 the 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 the Partnership to be treated as a “publicly traded partnership” or result in the termination of the 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. 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 63% to the Investor Partners and 37% to the Managing General Partner. Cash distributions began in May 2008. The following table presents the cash distributions made to the Investor Partners and Managing General Partner during the years indicated:

 
 
Year Ended December 31,
 
 
2011
 
2010
 
 
 
 
 
Cash distributions
 
$
5,410,042

 
$
14,355,892


Cash distributions to Partners were reduced by the withholding of funds for the Partnership’s future development of proved developed non-producing reserves and proved undeveloped reserves in the amount of $2,000,000 and $120,000 for 2011 and 2010, respectively. Cash distributions to Partners were further decreased in 2011 as compared to 2010 primarily due to the significant decrease in cash flows from operating activities during 2011.
v2.4.0.6
Transactions with Managing General Partner and Affiliates
12 Months Ended
Dec. 31, 2011
Related Party Transactions [Abstract]  
Related Party Transactions Disclosure [Text Block]
TRANSACTIONS WITH MANAGING GENERAL PARTNER AND AFFILIATES

The Managing General Partner transacts business on behalf of the Partnership under the authority of the D&O Agreement. Revenues and other cash inflows received from the Managing General Partner on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership. The fair value of the Partnership's portion of 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 Managing General Partner-other, net,” which remain undistributed or unsettled with the Partnership's investors as of the dates indicated.
    
 
December 31, 2011
 
December 31, 2010
Natural gas, NGLs and crude oil sales revenues
collected from the Partnership's third-party customers
$
738,787

 
$
875,468

Commodity price risk management, realized gain
274,775

 
478,306

Other (1)
(601,991
)
 
(819,659
)
Total Due from Managing General Partner-other, net
$
411,571

 
$
534,115


(1)
All other unsettled transactions, excluding derivative instruments, between the 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.

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 and its affiliates for the years ended December 31, 2011 and 2010. “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,
 
2011
 
2010
 Well operations and maintenance (1)
$
3,395,421

 
$
3,936,833

 Gathering, compression and processing fees (2)
406,821

 
529,849

 Direct costs - general and administrative (3)
213,327

 
200,907

 Cash distributions (4)
2,002,528

 
5,311,680


(1) Under the D&O Agreement, the Managing General Partner, as operator of the wells, receives payments for well charges and lease operating supplies and maintenance expenses from the Partnership when the wells begin producing.
Well charges. The Managing General Partner receives reimbursement at actual cost for all direct expenses incurred on behalf of the Partnership, monthly well operating charges for operating and maintaining the wells during producing operations, 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, or COPAS. 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 the 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 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, 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 the Partnership and government agencies.

The well supervision fees do not include costs and expenses related to:
the purchase or repairs of equipment, materials or third-party services;
the cost of compression and third-party gathering services, or gathering costs;
brine disposal; and
rebuilding of access roads.
These costs are charged at the invoice cost of the materials purchased or the third-party services performed.
Lease Operating Supplies and Maintenance Expense. The Managing General Partner and its affiliates may enter into other transactions with the Partnership for services, supplies and equipment during the production phase of the Partnership, and is entitled to compensation at competitive prices and terms as determined by reference to charges of unaffiliated companies providing similar services, supplies and equipment. Management believes these transactions were on terms no less favorable than could have been obtained from non-affiliated third parties.
(2) Under the Agreement, the Managing General Partner is responsible for gathering, compression, processing and transporting the natural 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 natural gas.
(3) The Managing General Partner is reimbursed by the Partnership for all direct costs expended by them on the Partnership’s behalf for administrative and professional fees, such as legal expenses, audit fees and engineering fees for reserve reports.
(4) The Agreement provides for the allocation of cash distributions 63% to the Investors Partners and 37% to the Managing General Partner. The Investor Partner cash distributions during 2011 include $812 for Investor Partner units repurchased by PDC. For additional disclosure regarding the allocation of cash distributions, refer to Note 8, Partners’ Equity and Cash Distributions.
v2.4.0.6
Impairment of Capitalized Costs
12 Months Ended
Dec. 31, 2011
Property, Plant and Equipment Impairment or Disposal [Abstract]  
Property, Plant and Equipment, Impairment [Policy Text Block]
IMPAIRMENT OF CAPITALIZED COSTS

The Partnership assesses its proved natural gas and crude oil properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Managing General Partner reasonably estimates the commodities to be sold. The Partnership considers the receipt of the annual reserve report from independent engineers to be a triggering event. Therefore, impairment tests are completed as of December 31 each year. 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 the Partnership's reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of the Partnership's proved natural gas and crude oil properties. If during the completion of the impairment test, net capitalized costs exceed undiscounted future net cash flows, as occurred for the year ended December 31, 2010, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis, which is predominantly unobservable data or inputs (Level 3), and is measured by the amount by which the net capitalized costs exceed their fair value. The Partnership's estimated production used in the impairment testing is taken from the annual reserve report (See Supplemental Natural Gas, NGL and Crude Oil Information –Unaudited—Net Proved Reserves). Estimated undiscounted future net cash flows are determined using prices from the forward price curve at the measurement date. Estimated discounted future net cash flows were determined utilizing a risk adjusted discount rate that is based on rates utilized by market participants that are commensurate with the risks inherent in the development of the underlying natural gas and crude oil reserves. A decline in the forward price curves used to estimate future cash flows at December 31, 2010, accompanied by lower reserves reflected in the Partnership's annual reserve report resulted in an impairment in the fourth quarter of 2010. This downward revision to the future net cash flows resulted primarily from an 8,034 MMcf, or 33.5%, decrease in future estimated natural gas production due to well economics and a reduction in prices from 2009. The Partnership recorded an impairment loss, the first natural gas and crude oil properties impairment recognized by the Partnership since it began operations in 2007, of $27.7 million for the year ended December 31, 2010. The impairment loss resulted from the downward revision to the fair value of discounted future net cash flows of production activities in the Piceance Basin in Colorado. There was no impairment in 2011.