Rockies Region 2006 Limited Partnership 10-Q 2009 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2009

or

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD ____________ TO ____________

Commission File Number   000-52787

Rockies Region 2006 Limited Partnership

(Exact name of registrant as specified in its charter)

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

1775 Sherman Street, Suite 3000, Denver, Colorado  80203

(Address of principal executive offices)     (zip code)

 (303) 860-5800

(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.

Yes  x  No  o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes £    No £

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definition of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:

Large accelerated filer     o	Accelerated filer     o
Non-accelerated filer     o	Smaller reporting company     x

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

As of April 30, 2009 the Partnership had 4,497.03 units of limited partnership interest and no units of general partnership interest outstanding.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

INDEX TO REPORT ON FORM 10-Q

		Page
PART I – FINANCIAL INFORMATION
Item 1.	Condensed Financial Statements (unaudited)
	Condensed Balance Sheets	1
	Condensed Statements of Operations	2
	Condensed Statements of Cash Flows	3
	Notes to Financial Unaudited Condensed Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 4T.	Controls and Procedures	21
PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	22
Item 1A.	Risk Factors	22
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
Item 3.	Defaults Upon Senior Securities	22
Item 4.	Submission of Matters to a Vote of Security Holders	22
Item 5.	Other Information	22
Item 6.	Exhibits	23
	SIGNATURES	24

PART I – FINANCIAL INFORMATION

Item 1.             Condensed Financial Statements (unaudited)

Rockies Region 2006 Limited Partnership
Condensed Balance Sheets
(unaudited)
	March 31,			December 31,
	2009			2008*
Assets
Current assets:
Cash and cash equivalents	$	207,438		$	203,462
Accounts receivable		768,707			1,173,324
Oil inventory		63,669			45,750
Due from Managing General Partner-derivatives		6,360,136			5,772,399
Due from Managing General Partner-other, net		1,979,277			2,372,921
Total current assets		9,379,227			9,567,856
Oil and gas properties, successful efforts method, at cost		97,569,825			97,606,701
Less: accumulated depreciation, depletion and amortization		(28,265,571	)		(25,706,395	)
Oil and gas properties, net		69,304,254			71,900,306
Due from Managing General Partner-derivatives		1,000,376			2,009,629
Total noncurrent assets		70,304,630			73,909,935
Total Assets	$	79,683,857		$	83,477,791
Liabilities and Partners' Equity
Current liabilities:
Accounts payable and accrued expenses	$	164,535		$	206,320
Total current liabilities		164,535			206,320
Due to Managing General Partner-derivatives		2,190,445			300,410
Asset retirement obligations		785,222			775,083
Total liabilities		3,140,202			1,281,813
Commitments and contingencies
Partners' equity:
Managing General Partner		23,385,137			25,476,495
Limited Partners - 4,497.03 units issued and outstanding		53,158,518			56,719,483
Total Partners' equity		76,543,655			82,195,978
Total Liabilities and Partners' Equity	$	79,683,857		$	83,477,791

*Derived from audited 2008 balance sheet.

 See accompanying notes to unaudited condensed financial statements.

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Rockies Region 2006 Limited Partnership
Condensed Statements of Operations
(unaudited)
	Three months ended March 31,
	2009			2008
Revenues:
Oil and gas sales	$	2,504,934		$	8,772,457
Oil and gas price risk management gain (loss), net		169,387			(4,226,614	)
Total revenues		2,674,321			4,545,843
Operating costs and expenses:
Production and operating costs		1,058,380			1,589,254
Direct costs - general and administrative		234,545			220,447
Depreciation, depletion and amortization		2,559,176			3,013,595
Accretion of asset retirement obligations		10,139			9,693
Total operating costs and expenses		3,862,240			4,832,989
Loss from operations		(1,187,919	)		(287,146	)
Gain on sale of leasehold		-			120,000
Interest income		7,126			30,406
Net loss	$	(1,180,793	)	$	(136,740	)
Net loss allocated to partners	$	(1,180,793	)	$	(136,740	)
Less: Managing General Partner interest in net loss		(436,893	)		(50,594	)
Net loss allocated to Investor Partners	$	(743,900	)	$	(86,146	)
Net loss per Investor Partner unit	$	(165	)	$	(19	)
Investor Partner units outstanding		4,497.03			4,497.03

 See accompanying notes to unaudited condensed financial statements.

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Rockies Region 2006 Limited Partnership
Condensed Statements of Cash Flows
(unaudited)
	Three months ended March 31,
	2009			2008
Cash flows from operating activities:
Net loss	$	(1,180,793	)	$	(136,740	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		2,559,176			3,013,595
Accretion of asset retirement obligations		10,139			9,693
Unrealized loss on derivative transactions		2,311,551			3,915,456
Gain on sale of oil and gas properties		-			(120,000	)
Changes in operating assets and liabilities:
Decrease in accounts receivable		404,617			225,058
Decrease in interest receivable		-			40,000
Increase in oil inventory		(17,919	)		-
Decrease  in accounts payable and accrued expenses		(41,785	)		(26,259	)
Decrease (increase) in due from/to Managing General Partner-other, net		393,725			(1,282,749	)
Net cash provided by operating activities		4,438,711			5,638,054
Cash flows from investing activities:
Capital expenditures for oil and gas properties		(13,252	)		-
Proceeds from Colorado sales tax refund on capital expenditures		50,047			-
Gain on sale of oil and gas properties		-			120,000
Net cash provided by investing activities		36,795			120,000
Cash flows from financing activities:
Distributions to Partners		(4,471,530	)		(6,781,188	)
Net cash used in financing activities		(4,471,530	)		(6,781,188	)
Net increase (decrease) in cash and cash equivalents		3,976			(1,023,134	)
Cash and cash equivalents, beginning of period		203,462			1,183,810
Cash and cash equivalents, end of period	$	207,438		$	160,676

 See accompanying notes to unaudited condensed financial statements.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

Note 1−General and Basis of Presentation

The Rockies Region 2006 Limited Partnership (the “Partnership” or the “Registrant”) was organized as a limited partnership on July 20, 2006, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and natural gas properties.  Upon completion of a sale of Partnership units on September 7, 2006 (date of inception), the Partnership was funded and commenced its business operations.  The Partnership owns natural gas and oil wells located in Colorado and North Dakota, and from the wells, it produces and sells natural gas and oil.

Purchasers of partnership units subscribed to and fully paid for 47.25 units of limited partner interests and 4,449.78 units of additional general partner interests at $20,000 per unit.  Petroleum Development Corporation, a Nevada Corporation, is the Managing General Partner of the Partnership (hereafter, the “Managing General Partner,” “MGP” or “PDC”). and has a 37% ownership in the Partnership.  Throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 63% to the limited and additional general partners (collectively, the “Investor Partners”), which are shared pro rata based upon the portion of units owned in the Partnership, and 37% to the Managing General Partner.

As of April 30, 2009, there were 2,028 Investor Partners.  As Managing General Partner, PDC has repurchased 5.5 units of the total 4,497.03 outstanding units of Partnership interests from Investor Partners at an average price of $23,804 per unit through April 30, 2009 and as such, participates in the sharing of revenues, costs and cash distributions as both an investor partner and as the Managing General Partner.

In accordance with the terms of the Limited Partnership Agreement (the “Agreement”), the Managing General Partner manages all activities of the Partnership and acts as the intermediary for substantially all Partnership transactions.  Upon completion of the drilling phase of the Partnership's wells, all additional general partners units were converted into units of limited partner interests and thereafter became limited partners of the Partnership.

The accompanying interim unaudited condensed financial statements have been prepared without audit in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Article 8 of Regulation S-X of the Securities and Exchange Commission, or SEC.  Accordingly, pursuant to certain rules and regulations, certain notes and other financial information included in audited financial statements have been condensed or omitted.  In the Partnership’s opinion, the accompanying interim unaudited condensed financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly the Partnership's financial position, results of operations and cash flows for the periods presented.  The interim results of operations and cash flows for the three months ended March 31, 2009 and 2008, are not necessarily indicative of the results to be expected for the full year or any other future period.

The accompanying condensed balance sheet as of December 31, 2008, was derived from audited financial statements, but as indicated above, may not include all disclosures required by accounting principles generally accepted in the United States of America.  The accompanying interim unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Partnership's Form 10-K for the year ended December 31, 2008, as filed with the SEC on March 31, 2009.

Reclassifications

Certain amounts in the prior period have been reclassified to conform with the current year classifications with no effect on previously reported net income or Partners’ equity.  For more information on these reclassifications, see Note 3, −Transactions with Managing General Partner and Affiliates.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

Note 2−Recent Accounting Standards

Recently Adopted Accounting Standards

In December 2007, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards, or FAS, No. 141 (revised 2007), Business Combinations, or FAS No. 141 (R).  FAS No. 141(R) requires an acquirer to recognize the assets acquired, the liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair values.  FAS No. 141(R) also requires disclosure of the information necessary for investors and other users to evaluate and understand the nature and financial effect of the business combination.  Additionally, FAS No. 141(R) requires that acquisition-related costs be expensed as incurred.  The provisions of FAS No. 141(R) are effective for acquisitions completed on or after January 1, 2009; however, the income tax provisions of FAS No. 141(R) became effective as of that date for all acquisitions, regardless of the acquisition date.  FAS No. 141(R) amends FAS No. 109, Accounting for Income Taxes, to require the acquirer to recognize changes in the amount of its deferred tax benefits recognizable due to a business combination either in income from continuing operations in the period of the combination or directly in contributed capital, depending on the circumstances.  FAS No. 141(R) further amends FAS No. 109 and FIN 48, Accounting for Uncertainty in Income Taxes, to require, subsequent to a prescribed measurement period, changes to acquisition-date income tax uncertainties to be reported in income from continuing operations and changes to acquisition-date acquiree deferred tax benefits to be reported in income from continuing operations or directly in contributed capital, depending on the circumstances.  In April 2009, the FASB issued FASB Staff Position, or FSP, No. FAS 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, amending the guidance of FAS No. 141(R) to required that assets acquired and liabilities assumed in a business combination that arise from contingencies be recognized at fair value if fair value can be reasonably estimated and if not, the asset and liability would generally be recognized in accordance with FAS No. 5, Accounting for Contingencies, and FASB Interpretation No. 14, Reasonable Estimation of the Amount of a Loss.  Further, FSP 141(R)-1 requires that certain acquired contingencies be treated as contingent consideration and measured both initially and subsequently at fair value.  The Partnership’s adoption of the provisions of FAS No. 141(R) and FSP 141(R)-1 effective January 1, 2009 had no impact on the Partnership’s financial statements.

In December 2007, the FASB issued FAS No. 160, Non-controlling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51.  FAS No. 160 states that accounting and reporting for minority interests will be recharacterized as non-controlling interests and classified as a component of equity.  Additionally, SFAS No. 160 establishes reporting requirements that provide sufficient disclosures which clearly identify and distinguish between the interests of the parent and the interests of the non-controlling owners.  The Partnership’s adoption of the provisions of FAS No. 160 effective January 1, 2009 did not have a material impact on the Partnership’s financial statements.

In February 2008, the FASB issued FSP No. 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of FAS No. 157, Fair Value Measurements, by one year (to January 1, 2009) for nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  Effective January 1, 2009, the Partnership adopted the provisions of FAS No. 157 delayed by FSP 157-2.  The adoption of FSP 157-2 did not have a material impact on the Partnership’s financial statements.  See Note 5, Fair Value Measurements.

In March 2008, the FASB issued FAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities.  Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  The Partnership’s adoption of FAS No. 161 effective January 1, 2009, did not have a material impact on the Partnership’s financial statements.  For more information on the Partnership’s derivative accounting, see Note 4, Derivative Financial Instruments.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

Recently Issued Accounting Standards

On April 9, 2009, the FASB issued two amendments to the fair value measurement and disclosure standards:

· FSP No. FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly and

· FSP No. FAS 107-1 and APB 28-1, Interim Disclosures about Fair Value of Financial Instruments.

FSP 157-4 affirms that the objective of fair value when the market for an asset is not active is the price that would be received to sell the asset in an orderly transaction; clarifies and includes additional factors for determining whether there has been a significant decrease in market activity for an asset when the market for that asset is not active; eliminates the proposed presumption that all transactions are distressed (not orderly) unless proven otherwise and instead requires an entity to base its conclusion about whether a transaction was not orderly on the weight of the evidence; requires an entity to disclose a change in valuation technique (and the related inputs) resulting from the application of the FSP and to quantify its effects, if practicable; and applies to all fair value measurements when appropriate.

FSP 107-1/APB 28-1 amends FAS No. 107, Disclosures about Fair Value of Financial Instruments, to require an entity to provide disclosures about fair value of financial instruments in interim financial information.  This FSP also amends Accounting Principles Board, or APB, Opinion No. 28, Interim Financial Reporting, to require those disclosures in summarized financial information at interim reporting periods.  Pursuant to this FSP, a reporting entity shall include disclosures about the fair value of its financial instruments whenever it issues summarized financial information for interim reporting periods.  In addition, an entity shall disclose in the body or in the accompanying notes of its summarized financial information for interim reporting periods and in its financial statements for annual reporting periods, the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not recognized in the statement of financial position, as required by SFAS No. 107.

These two amendments to fair value measurements and disclosure standards, FSP 157-4 and FSP 107-1/APB 28-1, are effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  However, early adoption is allowed only if certain FSPs are early-adopted together: an entity early-adopting FSP 157-4 must also early-adopt FSP FAS 115-2 and FAS 124-2, Recognition and Presentation of Other-Than-Temporary Impairments and an entity early adopting FSP 107-1/APB 28-1 must also elect to early-adopt FSP 157-4 and FSP 115-2/124-4.  The Partnership does not expect these FSPs to have a significant impact on the Partnership’s financial statements when adopted on April 1, 2009.

In January 2009, the SEC published its final rule, Modernization of Oil and Gas Reporting, which modifies the SEC’s reporting and disclosure rules for oil and natural gas reserves.  The most notable changes of the final rule include the replacement of the single day period-end pricing to value oil and natural gas reserves to a 12-month average of the first day of the month price for each month within the reporting period.  The final rule also permits voluntary disclosure of probable and possible reserves, a disclosure previously prohibited by SEC rules.  The revised reporting and disclosure requirements are effective for the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009.  Early adoption is not permitted.  The Managing General Partner is evaluating the impact that adoption of this final rule will have on the Partnership’s financial statements, related disclosure and management’s discussion and analysis.

Note 3−Transactions with Managing General Partner and Affiliates

The Managing General Partner transacts business on behalf of the Partnership.  Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the caption “Due from Managing General Partner–derivatives,” in the case of net unrealized gains or  “Due to Managing General Partner–derivatives,” in the case of net unrealized losses.  The fair value of derivative instruments previously reported at December 31, 2008, in which individual contracts held by each counterparty were aggregated, or netted, for determining presentation as a net asset, or net liability of the Partnership, have been reclassified to conform to the current year individual contract presentation methodology.

Undistributed oil and natural gas revenues collected by the Managing General Partner from the Partnership’s customers in the amount of $1,866,612 and $2,382,497 as of March 31, 2009 and December 31, 2008, respectively, are included in the balance sheet caption “Due from Managing General Partner - other, net.”  This $2,382,497 portion of undistributed oil and natural gas revenues at December 31, 2008, has been reclassified from “Accounts Receivable” to “Due from Managing General Partner – other, net” to conform to current year presentation.  Realized gains or losses that have not yet been distributed to the Partnership are included in the balance sheet captions “Due from Managing General Partner-other, net” or “Due to Managing General Partner-other, net,” respectively.  Undistributed realized gains amounted to $2,480,938 as of March 31, 2009 and $2,099,787 as of December 31, 2008, respectively.  At May 14, 2009, unsettled amounts due from derivative counterparties related to undistributed realized gains at March 31, 2009 were approximately $145,000.  All other unsettled transactions between the Partnership and the Managing General Partner are recorded net on the balance sheet under the caption “Due from (to) Managing General Partner – other, net.”

The following table presents transactions with the Managing General Partner and its affiliates for the periods described below.  Additionally, refer to Note 4, Derivative Financial Instruments for derivative transactions between the Partnership and the Managing General Partner.

	Three months ended March 31,
	2009		2008
Well charges	$	162,422	$	166,773
Supplies and equipment		658,961		706,751
Gathering, compression and processing fees		72,462		74,743
Direct costs - general and administrative		234,464		220,447
Cash distributions*		1,656,657		2,543,838

*Cash distributions include $2,193 and $1,727 during the three months ended March 31, 2009 and 2008, respectively, related to equity cash distributions on Investor Partner units repurchased by PDC.  For additional disclosure regarding the Unit Repurchase Program, refer to Note 1, General and Part II Item 2, Unregistered Sales of Equity Securities and Use of Proceeds.

Note 4−Derivative Financial Instruments

The Partnership is exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to oil and natural gas sales.  Price risk represents the potential risk of loss from adverse changes in the market price of oil and natural gas commodities.  The Managing General Partner employs established policies and procedures to manage the risks associated with these market fluctuations using derivative instruments.  Partnership policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

The Partnership accounts for derivative financial instruments in accordance with FAS No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended.  As of March 31, 2009, and December 31, 2008, none of the Partnership’s derivative instruments qualified for use of hedge accounting under the terms of FAS No. 133.  The Partnership recognizes all derivative instruments as either assets or liabilities on its balance sheets at fair value, and changes in the fair value of those derivative instruments allocated to the Partnership are recorded on a net basis in the Partnership’s statements of operations.  Changes in the fair value of derivative instruments related to the Partnership’s oil and gas sales activities are recorded in “Oil and gas price risk management loss, net.”

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

Valuation of a contract’s fair value is performed internally.  While the Managing General Partner uses common industry practices to develop the Partnership’s valuation techniques, changes in pricing methodologies or the underlying assumptions could result in different fair values.  See Note 5, Fair Value Measurements, for a discussion of how the Managing General Partner determines the fair value the Partnership’s derivative instruments.

As of March 31, 2009, the Managing General Partner had derivative contracts in place for a portion of the Partnership’s anticipated production through 2011 for a total of 2,299 MMbtu of natural gas and 85 MBbls of crude oil.

Risk Management Strategies.  The Partnership’s results of operations and operating cash flows are affected by changes in market prices for oil and natural gas.  To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative instruments. As of March 31, 2009, the Partnership’s oil and natural gas derivative instruments were comprised of natural gas collars and swaps, oil swaps and basis protection swaps.

· For swap instruments, if the market price is below the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and receives the difference between the market price and the fixed contract price from the counterparty.  If the market price is above the fixed contract price, PDC, as Managing General Partner, receives the market price from the purchaser and pays the difference between the market price and the fixed contract price to the counterparty.

· Basis protection swaps are arrangements that guarantee a price differential for natural gas valued at a specified pricing point, or hub.  For CIG basis protection swaps that have a negative pricing differential to NYMEX, PDC, as Managing General Partner, receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.

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

For Partnership oil and gas sales activities, the Managing General Partner purchases collars and swaps on the Partnership’s production to protect against price declines in future periods. While these derivatives are structured to reduce exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price changes in the physical market.  The Partnership believes the derivative instruments in place continue to be effective in achieving the risk management objectives for which they were intended.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

The Partnership’s derivative instruments are recorded at fair value determined in accordance with FAS No. 157.  The following table summarizes the location and fair value amounts of the Partnership’s derivative instruments in the accompanying balance sheets as of March 31, 2009, and December 31, 2008.

			Fair Value
			As of
Derivatives not qualifying for hedge		Balance Sheet	March 31,			December 31,
accounting under FAS No. 133 (1):		Location	2009			2008
Derivative Assets:	Current
	Commodity based derivative contracts	Due from Managing General Partner-derivatives	$	6,360,136		$	5,772,399
	Long Term
	Commodity based derivative contracts	Due from Managing General Partner-derivatives		1,000,376			2,009,629
Total Derivative Assets			$	7,360,512		$	7,782,028
Derivative Liabilities:	Long Term
	Commodity based derivative contracts	Due to Managing General Partner-derivatives	$	(162,160	)	$	-
	Basis protection derivative contracts	Due to Managing General Partner-derivatives		(2,028,285	)		(300,410	)
Total Derivative Liabilities			$	(2,190,445	)	$	(300,410	)

(1) As of March 31, 2009 and December 31, 2008, none of the Partnership’s derivative contracts qualified for hedge accounting under FAS No. 133.

The following table summarizes the location and amounts of gains and losses on derivative instruments in the Partnership’s accompanying statements of operations for the three months ended March 31, 2009 and 2008.

	Three months ended March 31,
	2009									2008
Statement of operations line item	Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total			Reclassification of Realized Gains (Losses) Included in Prior Periods Unrealized			Realized and Unrealized Gains (Losses) For the Current Period			Total
Oil and gas price risk management, gain (loss), net
Realized gains (losses)	$	2,059,706		$	421,232		$	2,480,938		$	503,015		$	(814,173	)	$	(311,158	)
Unrealized losses		(2,059,706	)		(251,845	)		(2,311,551	)		(503,015	)		(3,412,441	)		(3,915,456	)
Total oil and gas price risk management gain (loss), net	$	-		$	169,387		$	169,387		$	-		$	(4,226,614	)	$	(4,226,614	)

Concentration of Credit Risk. A significant portion of the Partnership’s liquidity is concentrated in derivative instruments that enables the Partnership to manage a portion of its exposure to price volatility from producing oil and natural gas.  These arrangements expose the Partnership to credit risk.  These contracts consist of fixed-price swaps, basis protection swaps and collars.  Credit risk is the failure of the counterparty to perform under the terms of the derivative contract.  When the fair value of a derivative contract is positive, the counterparty owes the Managing General Partner, which in turn owes the Partnership, thus creating repayment risk from counterparties.  The Managing General Partner seeks to diversify counterparty exposure by entering into transactions with high-quality counterparties including three investment grade financial institutions.  The Managing General Partner has evaluated the credit risk of the Partnership’s assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  Based on this evaluation, the Managing General Partner has determined that the impact of the nonperformance of counterparties on the fair value of the Partnership’s derivative instruments is insignificant.  The Managing General Partner has not experienced any counterparty defaults during the three months ended March 31, 2009, nor in any previous reporting period and no valuation allowance has been recorded by the Partnership.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

Note 5−Fair Value Measurements

Determination of Fair Value. The Partnership determines the fair value of its assets and liabilities, unless specifically excluded, pursuant to FAS No. 157.  FAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

FAS No. 157 establishes a fair value hierarchy that requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.  The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).  In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy.  The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy.  Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels.  The three levels of inputs that may be used to measure fair value are defined as:

· Level 1 –  Quoted prices (unadjusted) in active markets for identical assets or liabilities.  Included in Level 1 are commodity derivative instruments for New York Mercantile Exchange (“NYMEX”) natural gas swaps.

· Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability and (iv) inputs that are derived from observable market data by correlation or other means.

· Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Included in Level 3 are the Partnership’s asset retirement obligations and the Partnership’s commodity derivative instruments for CIG-based fixed-price natural gas swaps, collars and floors, oil swaps, and natural gas basis protection swaps.

Derivative Financial Instruments.  The Partnership measures fair value based upon quoted market prices, where available.  The Managing General Partner’s valuation determination includes: (1) identification of the inputs to the fair value methodology through the review of counterparty statements and other supporting documentation, (2) determination of the validity of the source of the inputs, (3) corroboration of the original source of inputs through access to multiple quotes, if available, or other information and (4) monitoring changes in valuation methods and assumptions.  The methods described above may produce a fair value calculation that may not be indicative of future fair values.  The Managing General Partner’s valuation determination also gives consideration to the nonperformance risk on Partnership liabilities in addition to nonperformance risk on PDC’s own business interests and liabilities, as well as the credit standing of derivative instrument counterparties.  The Managing General Partner primarily uses three investment grade financial institutions as counterparties to its derivative contracts.  The Managing General Partner has evaluated the credit risk of the Partnership’s derivative assets from counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position.  The Managing General Partner has determined based on this evaluation, that the impact of counterparty non-performance on the fair value of the Partnership’s derivative instruments is insignificant for the Partnership.  Thus, no valuation allowance has been recorded by the Partnership as of March 31, 2009.  Furthermore, while the Managing General Partner believes these valuation methods are appropriate and consistent with that used by other market participants, the use of different methodologies, or assumptions, to determine the fair value of certain financial instruments could result in a different estimate of fair value.

- 10 -

ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

The following table presents, by hierarchy level, the Partnership’s derivative financial instruments, including both current and non-current portions, measured at fair value for the period described:

	Level 1					Level 3
	As of					As of
	March 31, 2009			December 31, 2008		March 31, 2009			December 31, 2008
Assets:
Commodity based derivatives	$	-		$	-	$	7,360,512		$	7,782,028
Basis protection derivative contracts		-			-		-			-
Total assets		-			-		7,360,512			7,782,028
Liabilities:
Commodity based derivatives		(156,643	)		-		(5,517	)		-
Basis protection derivative contracts		-			-		(2,028,285	)		(300,410	)
Total liabilities		(156,643	)		-		(2,033,802	)		(300,410	)
Net Asset	$	(156,643	)	$	-	$	5,326,710		$	7,481,618

The following table sets forth a reconciliation of the Partnership’s Level 3 derivative financial instruments measured on a recurring basis:

	Three months ended
	March 31, 2009
Fair value, net asset, as of December 31, 2008	$	7,481,618
Unrealized and realized gains (losses) included in Oil and gas price risk management gain, net		326,030
Settlements, net		(2,480,938	)
Fair value, net asset, as of March 31, 2009	$	5,326,710
Change in unrealized gains (losses) relating to assets (liabilities) still held as of March 31, 2009, included in statement of operations line item:
Oil and gas price risk management gain, net	$	(89,685	)

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

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

In accordance with Statement of Financial Accounting Standards, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the Partnership reviews its proved oil and gas properties for possible impairment, upon a triggering event, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which the Partnership reasonably estimates the commodity to be sold.  The estimates of future prices may differ from current market prices of oil and natural gas.  Downward revisions in estimates to the Partnership’s reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event and therefore a possible impairment of the Partnership’s oil and natural gas properties.  If net capitalized costs exceed undiscounted future net cash flows, impairment is measured by the amount by which the net capitalized costs exceed their fair value utilizing a future discounted cash flow analysis.  There were no triggering events and no impairment of oil and gas properties has been recognized during the three months ended March 31, 2009.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

March 31, 2009

(unaudited)

The Partnership accounts for asset retirement obligations by recording the estimated fair value of the plugging and abandonment obligations when incurred, which is when the well is completely drilled.  The Partnership estimates the fair value of the plugging and abandonment obligations based on a discounted cash flows analysis.  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 their present value, through charges to oil and gas production and well operations costs.  The initial capitalized costs are depleted over the useful lives of the related assets, through charges to depreciation, depletion and amortization.  If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost.  Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.

Note 6−Commitments and Contingencies

Royalty Settlement.  On May 29, 2007, Glen Droegemueller, individually and as representative plaintiff on behalf of all others similarly situated, filed a class action complaint against the Managing General Partner in the District Court, Weld County, Colorado alleging that the Managing General Partner underpaid royalties on natural gas produced from wells operated by the Managing General Partner in parts of the State of Colorado (the “Droegemueller Action”).  The plaintiff sought declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by us pursuant to leases.  The Managing General Partner removed the case to Federal Court on June 28, 2007.  On October 10, 2008, the court preliminarily approved a settlement agreement between the plaintiffs and the Managing General Partner, on behalf of itself and the Partnership.  Although the Partnership was not named as a party in the suit, the lawsuit states that it relates to all wells operated by the Managing General Partner, which includes a majority of the Partnership’s 64 wells in the Wattenberg field.  The portion of the settlement relating to the Partnership’s wells for all periods through March 31, 2009 that has been expensed by the Partnership is approximately $175,000 including associated legal costs of approximately $12,000.  Such moneys, on behalf of the Partnerships, were deposited in an escrow account on November 3, 2008.  The Managing General Partner believes that the amount accrued is adequate to satisfy this obligation.  Notice of the settlement was mailed to members of the class action suit in the fourth quarter of 2008.  The final settlement was approved by the court on April 7, 2009.  Distributions from the escrow to the royalty owners are expected on or before June 7, 2009, unless the court approval of the settlement is appealed.

Stormwater Permit.  On December 8, 2008, the Managing General Partner received a Notice of Violation /Cease and Desist Order (the “Notice”) from the Colorado Department of Public Health and Environment, related to the stormwater permit for the Garden Gulch Road.  The Managing General Partner manages this private road for Garden Gulch LLC.  The Managing General Partner is one of four equal owners of Garden Gulch LLC, all of which are oil and gas companies operating in the Piceance region of Colorado.  The Partnership has 23 wells in this region.  The Notice alleges a deficient and/or incomplete stormwater management plan, failure to implement best management practices and failure to conduct required permit inspections.  The Notice requires corrective action and states that the recipient shall cease and desist such alleged violations.  The Notice states that a violation could result in civil penalties up to $10,000 per day.  The Managing General Partner’s responses were submitted on February 6, 2009, and April 8, 2009.  Given the preliminary stage of this proceeding and the inherent uncertainty in administrative actions of this nature, the Managing General Partner is unable to predict the ultimate outcome of this administrative action at this time.

Derivative Contracts.  The Partnership is exposed to oil and natural gas price fluctuations on underlying sales contracts should the counterparties to the Managing General Partner’s derivative instruments not perform.  Nonperformance is not anticipated.  The Managing General Partner has had no counterparty default losses to date.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 2.      Management’s Discussion and Analysis of Financial Condition and Results of Operations

Special Note Regarding Forward-Looking Statements

This periodic report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) regarding Rockies Region 2006 Limited Partnership (the “Partnership’s” or the “Registrant’s”) business, financial condition, results of operations and prospects that are subject to risks and uncertainties.  Words such as “expects,” “anticipates,” “intends,” “plans,” “believes,” “seeks,” “estimates” and similar expressions or variations of such words are intended to identify forward-looking statements herein, which include statements of estimated oil and natural gas production and reserves, drilling plans, future cash flows, anticipated liquidity, anticipated capital expenditures and the Managing General Partner Petroleum Development Corporation’s (“MGP’s” or “PDC’s”) strategies, plans and objectives.  However, these are not the exclusive means of identifying forward-looking statements herein.  Although forward-looking statements contained in this report reflect the Managing General Partner's good faith judgment, such statements can only be based on facts and factors currently known to them.  Consequently, forward-looking statements are inherently subject to risks and uncertainties, including risks and uncertainties incidental to the development, production and marketing of natural gas and oil, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to:

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

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

· future production and development costs;

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

· the effect of existing and future laws, governmental regulations and the political and economic climate of the United States of America (“U.S.”) and the impact of the global economy;

· the effect of natural gas and oil derivatives activities;

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

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

Overview

Rockies Region 2006 Limited Partnership engages in the development, production and sale of oil and natural gas.  The Partnership began oil and gas operations in September 2006 and currently operates 91 gross (90.4 net) wells located in the Rocky Mountain Region in the states of Colorado and North Dakota.  The Partnership sells the produced natural gas to commercial end users, interstate or intrastate pipelines or local utilities, primarily under market sensitive contracts in which the price of natural gas sold varies as a result of market forces.  PDC, on behalf of the Partnership, may enter into fixed price contracts, or utilize derivatives, including collars, swaps or basis protection swaps, in order to offset some or all of the price variability for particular periods of time, generally for two to three years, but in no cases longer than five years.  Seasonal factors, such as effects of weather on prices received and costs incurred, and availability of pipelines may impact the Partnership's results.  In addition, both sales volumes and prices tend to be affected by demand factors with a significant seasonal component.

PDC last sponsored a drilling partnership (Rockies Region 2007 Limited Partnership) in the fall of 2007, and substantially completed the last drilling services for that partnership in 2008.  PDC does not currently have any plans to sponsor additional drilling partnerships.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

The table below sets forth selected information regarding the Partnership’s results of operations, including production volumes, oil and gas sales, average sales prices received, average sales price including realized derivative gains and losses, production and operating costs, depreciation, depletion and amortization costs, other operating income and expenses for the three months ended March 31, 2009, or first quarter of 2009 and the three months ended March 31, 2008, or first quarter of 2008.

	Summary of Operating Results
	Three months ended March 31,
	2009			2008			Change
Number of producing wells (end of period)		91			91			*
Production:  (1)
Oil (Bbl)		29,628			45,987			-36	%
Natural gas (Mcf)		498,993			683,884			-27	%
Natural gas equivalents (Mcfe)  (2)		676,761			959,806			-29	%
Average Selling Price
Oil (per Bbl)  (3)	$	35.12		$	85.03			-59	%
Natural gas (per Mcf)  (3)		2.93			7.11			-59	%
Natural gas equivalents (per Mcfe)  (3)		3.70			9.14			-60	%
Average Selling Price (including realized gain (loss), net on derivatives)
Oil (per Bbl)	$	56.84		$	79.10			-28	%
Natural gas (per Mcf)		6.62			7.05			-6	%
Natural gas equivalents (per Mcfe)		7.37			8.82			-16	%
Average cost per Mcfe
Production and operating costs  (4)	$	1.56		$	1.66			-6	%
Depreciation, depletion and amortization		3.78			3.14			20	%
Revenues:
Oil and gas sales	$	2,504,934		$	8,772,457			-71	%
Oil and gas price risk management, gain (loss), net		169,387			(4,226,614	)		*
Total revenues	$	2,674,321		$	4,545,843			-41	%
Realized Gain (Loss) on Derivatives, net
Oil derivatives - realized gain (loss)	$	643,598		$	(182,219	)		*
Natural gas derivatives - realized gain (loss)		1,837,340			(128,939	)		*
Total realized gain (loss) on derivatives, net	$	2,480,938		$	(311,158	)		*
Operating costs and expenses:
Production and operating costs	$	1,058,380		$	1,589,254			-33	%
Direct costs - general and administrative		234,545			220,447			6	%
Depreciation, depletion and amortization		2,559,176			3,013,595			-15	%
Accretion of asset retirement obligations		10,139			9,693			5	%
Total operating costs and expenses	$	3,862,240		$	4,832,989			-20	%
Loss from operations	$	(1,187,919	)	$	(287,146	)		*
Gain on sale of leasehold		-			120,000			*
Interest income		7,126			30,406			-77	%
Net loss	$	(1,180,793	)	$	(136,740	)		*
Cash distributions	$	4,471,530		$	6,781,188			-34	%

*Percentage change not meaningful or equal to or greater than 250% or not calculable.  Amounts may not calculate due to rounding

_______________

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

(2) A ratio of energy content of natural gas and oil (six Mcf of natural gas equals one Bbl of oil) was used to obtain a conversion factor to convert oil production into equivalent Mcf of natural gas.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

(4) Production costs represent oil and gas operating expenses which include production taxes.

Definitions used throughout Management’s Discussion and Analysis of Financial Condition and Results of Operations:

· Bbl – One barrel or 42 U.S. gallons liquid volume

· MBbl – One thousand barrels

· Mcf – One thousand cubic feet

· MMcf – One million cubic feet

· Mcfe – One thousand cubic feet of natural gas equivalents

· MMcfe – One million cubic feet of natural gas equivalents

First Quarter 2009 Overview

During the first quarter of 2009, the Partnership experienced the continuation of the significant declines in oil and natural gas commodity prices from last year, which was a year of significant events: oil and natural gas prices reached a record and near record highs through July; then, in the midst of U.S. credit turmoil and a worldwide economic slump, in December, oil prices fell to their lowest in four years and natural gas prices dropped almost by half. The Partnership’s derivative positions have eased the impact of the fall in oil and natural gas prices.  The Partnership realized $2.5 million in realized derivative gains in the first quarter of 2009, up from $2.1 million in the fourth quarter of 2008.  At March 31, 2009, the Partnership estimated the net fair value of its derivative positions to be $5.2 million.  See the Liquidity and Capital Resources discussion below for the steps the Partnership is taking in this uncertain economic environment.

Consistent with the historically declining production curves for wells drilled in the Wattenberg and Piceance fields, which have initial high production rates and associated rapid decline in the first two years followed by years of relatively shallow decline, Partnership production decreased to 677 MMcfe for the first three months of 2009.  First quarter 2009 production decreased 29% over the 960 MMcfe produced during the same period last year.  Coupled with the expected aspects of Rocky Mountain oil and natural gas field production life cycles however, were the significant developments in the national energy commodity markets, which was the primary factor in the Partnership’s average sales price decline of $5.44 per Mcfe, over the three months ended March 31, 2008.  Declining oil and natural gas prices during the first quarter of 2009 resulted in $2.5 million in realized gains on oil and natural gas derivatives for the three months ended March 31, 2009.  The Partnership’s $2.5 million realized derivative gains for the first quarter of 2009 added revenues, on average $3.67 per Mcfe, for production during the current three month period, somewhat easing the dramatic drop in commodity pricing.

A decrease in the spread between the NYMEX and CIG prices for natural gas, slightly offset by lower CIG natural gas prices, resulted in the $0.3 million unrealized losses on oil and natural gas derivatives during the quarter.  An unrealized loss is a non-cash item and further gains or losses will be recognized as prices decrease or increase until the positions mature or are closed.  None of the Partnership’s derivative instruments qualified for use of hedge accounting under the terms of FAS No. 133 during the current reporting period.  While the required accounting treatment for derivatives that do not qualify for hedge accounting treatment under SFAS No. 133 may result in significant swings in operating results over the life of the derivatives, the combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.

During the three month period ended March 31, 2009, daily crude oil prices fluctuated in a range of $33.98 to $54.34 per barrel, with the overall trend of the monthly average of daily NYMEX-index oil prices rising, from $41.99 per barrel in January to $48.12 per barrel in March.  Rocky Mountain regional natural gas daily prices tracked downward through March 2009 however, when the monthly average of daily CIG-index prices of $3.67 in January, declined to $2.50 by March.  See Oil and Gas Price Risk Management, Net discussion below.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The table below, which demonstrates the markets expected volatility in commodity pricing, sets forth the average NYMEX and CIG prices for the next 24 months (forward curve) from the selected dates:

		December 31,		June 30,		December 31,		March 31,
Commodity	Index	2007		2008		2008		2009
Natural gas: (per MMbtu)
	NYMEX	$	8.12	$	12.52	$	6.62	$	5.44
	CIG		6.78		8.86		4.49		4.15
Oil: (per Bbl)	NYMEX		90.79		140.15		57.49		59.35

Oil and Natural Gas Sales Activity

Partnership production for the current three month period was 677 MMcfe, averaging 7,520 Mcfe per day, a 29% decrease from the 10,547 Mcfe per day produced during the same three month period in 2008.  Weighted average prices (excluding realized gains or losses on derivatives) were $3.70 per Mcfe for the current three month period compared to $9.14 for the prior year’s same three-month period.  Decreased production and commodity prices contributed $2.6 million and $3.7 million, respectively, to the total decrease of $6.3 million in oil and gas sales revenue for the current three month period as compared to the prior year’s same three month period.  Oil and gas production continues to follow the anticipated production curve decline for wells in the Colorado region.

This change in production volumes is consistent with the historically declining production curves for wells drilled in the Wattenberg and Piceance fields.  The quarter-to-quarter decrease in both oil and natural gas revenues of 73% and 70%, respectively, reflects the historically steeper decline in oil production volumes (36%) than natural gas (27%) during the earlier portions of the production life cycle while crude oil and natural gas sales prices both declined 59%, during the comparison periods.  On an energy equivalency basis, or Mcfe, crude oil represents 26% of the Partnership’s hydrocarbon production with natural gas comprising the remaining 74%.  The Partnership expects to experience continued declines in both oil and natural gas production volumes over the wells’ life cycles until the Wattenberg wells are recompleted.

Oil and Natural Gas Pricing

Financial results depend upon many factors, particularly the price of oil and natural gas and the Partnership’s ability to market its production effectively.  Oil and natural gas prices have been among the most volatile of all commodity prices.  These price variations have a material impact on the Partnership’s financial results.  Oil and natural gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region.  The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply situation from time to time.  Like most producers in the region, the Partnership relies on major interstate pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond the Partnership’s control.  Oil pricing is also driven strongly by supply and demand relationships.  Beginning January 1, 2009, Suncor Energy Marketing, Inc. (“Suncor”) became the primary purchaser of the Partnership’s crude oil production.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The price the Partnership receives for the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which primarily includes natural gas sold at CIG prices with a portion sold at Mid-Continent or other nearby region prices.  The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX based.

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

The Managing General Partner uses oil and natural gas 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 operation.  Prior to September 30, 2008, as volumes produced changed, the mix between PDC and the partnerships would change.  As of September 30, 2008, PDC has fixed the allocation of the derivative positions between PDC and each partnership.  Existing positions are allocated based on fixed quantities for each position and new positions will have specific designations relative to the applicable partnership.

The following table presents the primary composition of “Oil and gas price risk management gain (loss), net” for the periods described:

	Three months ended March 31,
	2009			2008
Realized gain (loss)
Oil	$	643,598		$	(182,219	)
Natural Gas		1,837,340			(128,939	)
Total realized gain (loss), net		2,480,938			(311,158	)
Reclassification of realized gain included in prior periods unrealized gain		(2,059,706	)		(503,015	)
Unrealized loss for the period		(251,845	)		(3,412,441	)
Oil and gas price risk management, gain (loss), net	$	169,387		$	(4,226,614	)

The unrealized loss for the first quarter 2009 of $0.3 million was primarily due to a decrease in fair value from our CIG basis protection swaps of $1.7 million offset in part by a $1.4 million unrealized gain from our commodity derivatives.  The net unrealized gain from commodity derivatives resulted from the continued decline in commodity prices during the first quarter.  The unrealized loss from the Partnership’s CIG basis protection swaps resulted from a more significant decline in NYMEX pricing compared to CIG pricing.  The realized gains from commodity derivatives resulted from the current realized prices being below our swaps and floor contract prices.  Oil and gas price risk management loss, net includes realized gains and losses and unrealized gains and losses resulting from changes in the fair value of derivative instruments related to our oil and natural gas production.

Oil and Gas Derivative Activities.  The Managing General Partner uses various derivative instruments to manage fluctuations in oil and natural gas prices.  The Partnership has in place a series of collars, fixed price swaps and basis protection swaps on a portion of the Partnership’s oil and natural gas production.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table identifies the Partnership’s derivative positions related to oil and gas sales activities in effect as of March 31, 2009, on the Partnership’s production by area of operation.  The Partnership’s production volumes for the three months ended March 31, 2009, were 29,628 Bbls of oil and 498,993 Mcf of natural gas.  No new positions have been entered into subsequent to March 31, 2009, through May 12, 2009.

	Floors				Ceilings				Swaps (Fixed Prices)				Basis Protection Contracts
Commodity/Index/Operating Area	Quantity (Gas-MMbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-MMbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-MMbtu Oil-Bbls)		Weighted Average Contract Price		Quantity (Gas-MMbtu Oil-Bbls)		Weighted Average Contract Price		Fair Value At March 31, 2009
Natural Gas
Rocky Mountain Region
CIG
2Q 2009		354,661	$	5.75		354,661	$	8.90		-	$	-		-	$	-	$	1,162,157
3Q 2009		354,661		5.75		354,661		8.90		-		-		-		-		1,018,918
4Q 2009		241,573		6.64		241,573		10.18		86,574		9.20		-		-		1,267,028
2010		264,432		6.67		264,432		10.81		129,861		9.20		754,971		1.88		759,224
2011		119,105		4.75		119,105		9.45		-		-		842,171		1.88		(522,839	)
2012		-		-		-		-		-		-		850,609		1.88		(621,940	)
2013		-		-		-		-		-		-		763,070		1.88		(482,446	)
NYMEX
2010		31,517		5.75		31,517		8.30		673,914		5.55		-		-		(155,683	)
2011		42,413		5.75		42,413		8.30		-		-		-		-		(6,477	)
Total Natural Gas																		2,417,942
Oil
Rocky Mountain Region
NYMEX
2Q 2009		-		-		-		-		13,755		90.52		-		-		532,382
3Q 2009		-		-		-		-		13,907		90.52		-		-		488,200
4Q 2009		-		-		-		-		13,907		90.52		-		-		447,419
2010		-		-		-		-		43,382		92.96		-		-		1,284,124
Total Oil																		2,752,125
Total Natural Gas and Oil																	$	5,170,067

Production and Operating Costs

Generally, production and operating costs vary either with total oil and natural gas sales or production volumes.  Property and severance taxes are estimates by the Managing General Partner based on rates determined using historical information.  These amounts are subject to revision based on actual amounts determined during future filings by the Managing General Partner with the taxing authorities.  Property and severance taxes vary directly with total oil and natural gas sales.  Transportation costs vary directly with production volumes.  Fixed monthly well operating costs increase on a per unit basis as production decreases per the historical decline curve.  General oil field services and all other costs vary and can fluctuate based on services required.  These costs include water hauling and disposal, equipment repairs and maintenance, snow removal and service rig workovers.  In addition, general oil field service costs have experienced significant inflationary increases.

The 29% decline in oil and natural production, on an energy equivalency-basis, along with a decrease in general and field service costs resulted in a reduction of production and operating costs for the three months ended March 31, 2009 compared to 2008, of $0.5 million.  Operating costs per Mcfe were $1.56 for the first quarter of 2009 compared to $1.66 for the first quarter of 2008.

Direct Costs−General and Administrative

Direct costs – general and administrative consist primarily of professional fees for financial statement audits, income tax return preparation and legal matters.  Direct costs remained approximately the same during the first three months of 2009 compared to the same period in 2008, with slight increases in professional services partially offset with reductions in administrative costs.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (DD&A) results solely from the depreciation, depletion and amortization of well equipment and lease costs.  DD&A expense is directly related to reserves and production volumes.  DD&A expense is primarily based upon year-end proved developed producing oil and gas reserves.  These reserves are priced at the price of oil and natural gas as of December 31 each year.  If prices increase, the corresponding volume of oil and gas reserves will increase, resulting in decreases in the rate of DD&A per unit of production.  If prices decrease, as they did from 2007 to 2008, volumes of oil and gas reserves will decrease resulting in increases in the rate of DD&A per unit of production.

The increase in the per Mcfe rate to $3.78 for the quarter ended March 31, 2009 compared to the per Mcfe rate of $3.14 during the same quarter in 2008 resulted in a $0.5 million decrease in DD&A for the three months ended March 31, 2009 compared to same period in 2008.  This is primarily the result of a production level decrease of 29% offset by an increase per Mcfe due to lower reserves at December 31, 2008 compared to December 31, 2007.  While both production and overall year-end reserves are expected to decline gradually year-to-year over the wells’ remaining life cycles, downward revisions to oil and natural gas reserves in the annual 2008 reserve report, resulted in the larger DD&A unit cost increase during the first quarter of 2009 as compared to the first quarter 2008.

Interest Income

Interest income decreased in March 31, 2009 compared to the same period in the previous year, primarily due to lower interest rates applied to somewhat lower undistributed revenue amounts held by the Managing General Partner for the three months ended March 31, 2009 as compared to the three months ended March 31, 2008.

Liquidity and Capital Resources

The Partnership could not maintain the Partnership’s current level of oil and gas production and cash flows from operations if commodity prices remain in their current depressed state for a prolonged period beyond 2009, which would have a material negative impact on the Partnership’s operations in 2010 and beyond.

Working Capital

Working capital at March 31, 2009 was $9.2 million compared to working capital of $9.3 million at December 31, 2008.

Investing Cash Flows

In 2009, the Partnership received a $50,047 refund from the State of Colorado for state sales taxes charged during 2007 on well tubing and casing purchases during the Partnership’s drilling operations, which were subsequently determined to be tax-exempt.  The Partnership has from time-to-time, invested in additional equipment which supports treatment, delivery and measurement or environmental protection. Such amounts totaled approximately $13,000 for the three months ended March 31, 2009.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Financing Cash Flows

The Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $51.3 million of operating cash flows through March 31, 2009.  The table below sets forth the cash distributions to the Managing General Partner and Investor Partners including Managing General distribution relating to limited partnership units repurchased for the periods described as follows:

	Managing		Investor
Quarter	General Partner		Partners		Total
Ended	Distributions		Distributions		Distributions
March 31, 2009	$	1,654,464	$	2,817,066	$	4,471,530
March 31, 2008	$	2,542,111	$	4,239,077	$	6,781,188

Operating Cash Flows

The Partnership’s operations are expected to be conducted with available funds and revenues generated from its oil and natural gas production activities.  Changes in cash flow from operations are largely due to the same factors that affect the Partnership’s net income that are more fully discussed under Results of Operations, excluding the non-cash items depreciation, depletion and amortization and unrealized gains and losses on derivative transactions.  Based on current oil and natural gas prices and prices set by derivatives, and the Partnership’s anticipated production, the Partnership expects positive cash flows from operations for the remainder of 2009.

Changes in market prices for oil and natural gas, the Partnership’s ability to increase production, the impact of realized gains and losses on the Partnership’s oil and natural gas derivative instruments and changes in costs are the principal determinants of the level of the Partnership cash flow from operations.  Oil and natural gas sales for the three months ended March 31, 2009 were approximately 71% lower than the prior year, resulting from a 60% decrease in average oil and natural gas prices and a 29% decrease in oil and natural gas production.  While a decline in oil and natural gas prices would affect the amount of cash from operations that would be generated, the Partnership has oil and natural gas derivative positions in place, as of the date of this filing, covering 56% of the Partnership’s expected oil production and 74% of its expected natural gas production in 2009, at average prices of $90.52 per Bbl and $6.25 per Mcf, respectively.  These contracts reduce the impact of price changes on cash provided by operations for a substantial portion of the Partnership’s 2009 expected production.

The Partnership’s current derivatives positions could change based on changes in oil and natural gas futures markets, the view of underlying oil and natural gas supply and demand trends and changes in volumes produced.  Partnership oil and natural gas derivatives as of March 31, 2009 are detailed in Note 4, Derivative Financial Instruments to the accompanying unaudited condensed financial statements.

Net cash provided by operating activities was $4.4 million for the three months ended March 31, 2009 compared to $5.6 million during the same period in 2008, a decrease of $1.2 million or 21%.  The decrease in cash provided by operating activities was due primarily to the following:

· A decrease in oil and gas sales revenues of $6.3 million, or 71%, accompanied by an increase in direct costs – general and administrative of 6%.

· a $2.8 million increase in realized oil and gas price risk management loss, net and by a decrease in production and operating cost of 33%.

Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in the Partnership’s Annual Report on Form 10-K Supplemental Oil and Gas Information−Unaudited, Net Proved Oil and Gas Reserves and Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves.

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

PDC, as Managing General Partner, does not believe liquidity relative to its own business interests, nor that of the Partnership, has been materially affected by the recent events in the credit markets.  The Managing General Partner continues to monitor events and circumstances surrounding lenders in its credit facility and has experienced no disruptions in its ability to access this facility.  However, the Managing General Partner cannot predict with any certainty the impact to the Partnership of any continued disruption in the credit environment.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Commitments and Contingencies

See Note 6, Commitments and Contingencies, to the accompanying unaudited condensed financial statements.

Critical Accounting Policies and Estimates

The preparation of the accompanying unaudited condensed financial statements, in conformity with accounting principles generally accepted in the United States of America, requires management to use judgment in making estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities and the reported amounts of revenue and expenses.

The Managing General Partner believes that the Partnership’s accounting policies for revenue recognition, derivatives instruments, fair value measurements, oil and natural gas properties, and asset retirement obligations are based on, among other things, judgments and assumptions made by management that include inherent risks and uncertainties.  There have been no significant changes to these policies or in the underlying accounting assumptions and estimates used in these critical accounting policies from those disclosed in the financial statements and accompanying notes contained in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, filed with the SEC on March 31, 2009.  Certain amounts reported at December 31, 2008, more fully detailed in Note 3, −Transactions with Managing General Partner and Affiliates to the accompanying financial statements, have been reclassified on the Partnership’s balance sheet to conform with the current year classifications with no effect on previously reported net income or Partners’ equity.  Reclassifications include amounts related to undistributed oil and gas revenues and the fair value of unexpired derivative instruments.

Recent Accounting Standards

See Note 2, Recent Accounting Standards to the accompanying unaudited condensed financial statements, included in this report for recent accounting standards.

Item 3.         Quantitative and Qualitative Disclosures About Market Risk

Not Applicable

Item 4T.       Controls and Procedures

The Partnership has no direct management or officers.  The management, officers and other employees that provide services on behalf of the Partnership are employed by the Managing General Partner.

2008 Material Weakness

As discussed in Management’s Report on Internal Control Over Financial Reporting included in the Partnership’s 2008 Annual Report on Form 10-K, the Partnership did not maintain effective internal controls over financial reporting as of December 31, 2008, over transactions that are directly related to and processed by the Partnership, in that the Partnership failed to maintain sufficient documentation to adequately assess the operating effectiveness of internal control over financial reporting.  More specifically, the Partnership’s financial close and reporting narrative failed to adequately describe the process, identify key controls and assess segregation of duties.  This material weakness has not yet been remediated as of March 31, 2009.  The 2008 Annual Report on Form 10-K did not include an attestation report of the Partnership’s independent registered public accounting firm regarding internal control over financial reporting pursuant to Item 308T (a)(4) of Regulation S-K.  Such report is required in the Partnership’s 2009 Annual Report on Form 10-K.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

(a)  Evaluation of Disclosure Controls and Procedures

As of March 31, 2009, PDC, as Managing General Partner on behalf of the Partnership, carried out an evaluation, under the supervision and with the participation of the Managing General Partner's management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Partnership's disclosure controls and procedures.  Pursuant to Securities Exchange Act Rules 13a-15(e) and 15d-15(e), these are the controls and procedures of an issuer that are designed to ensure that information required to be disclosed by the issuer in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to the issuer’s management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Based upon that evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were not effective as of March 31, 2009 due to the existence of the material weakness described above in 2008 Material Weakness included in this Item 4 (T).

(b)  Remediation of Material Weakness in Internal Control

The Partnership has completed the planning phase for developing a revised financial close and reporting narrative which will adequately describe the process, identify key controls and assess segregation of duties.  This revised narrative is expected to be completed by the second quarter of 2009.  At present, the Partnership has not quantified the total cost of this initiative, however the majority of this cost is expected to be paid by the Managing General Partner.

PART II – OTHER INFORMATION

Item 1.            Legal Proceedings

Information regarding the Registrant’s legal proceedings can be found in Note 6, Commitments and Contingencies, to the Partnership’s accompanying unaudited condensed financial statements.

Item 1A.         Risk Factors

Not Applicable

Item 2.            Unregistered Sales of Equity Securities and Use of Proceeds

Unit Repurchase Program:  Beginning May 2010, the third anniversary of the date of the first Partnership cash distributions, Investor Partners of the Partnership may request that the Managing General Partner repurchase their respective individual Investor Partner units, up to an aggregate total limit during any calendar year for all requesting Investor Partner unit repurchases of 10% of the initial subscription units.

Other Repurchases:  Individual investor partners periodically offer and PDC repurchases, units on a negotiated basis before the third anniversary of the date of the first cash distribution.  There were no first quarter 2009 repurchases.  Second quarter 2009 repurchases were made in April 2009 when 2.0 units were repurchased at an average price of $12,960 per unit.

Items 3, 4 and 5 have been omitted as there is nothing to report.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 6.             Exhibits

(a)       Exhibit Index.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	SEC File Number	Exhibit	Filing Date	Filed Herewith
3.1	Limited Partnership Agreement	10-12G/A Amend 1	000-52787	3	12/24/2007
3.2	Certificate of limited partnership which reflects the organization of the Partnership under West Virginia law	10-12G/A Amend 1	000-52787	3.1	12/24/2007
10.1	Domestic Crude Oil Purchase Agreement between Suncor Energy Marketing Inc. and Petroleum Development Corporation, dated April 22, 2008*					X
31.1	Rule 13a-14(a)/15d-14(c) Certification of Chief Executive Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership as adopted pursuant to Section of the Sarbanes-Oxley Act of 2002.					X
31.2	Rule 13a-14(a)/15d-14(c) Certification of Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership as adopted pursuant to Section of the Sarbanes-Oxley Act of 2002.					X
32.1	Title 18 U.S.C. Section 1350 (Section 906 of Sarbanes-Oxley Act of 2002) Certifications by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership.					X

_________________

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

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Rockies Region 2006 Limited Partnership

By its Managing General Partner

Petroleum Development Corporation

By: /s/ Richard W. McCullough

Richard W. McCullough

Chairman and Chief Executive Officer

May 18, 2009

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ Richard W. McCullough	Chairman and Chief Executive Officer	May 18, 2009
Richard W. McCullough	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal executive officer)
/s/ Gysle R. Shellum	Chief Financial Officer	May 18, 2009
Gysle R. Shellum	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal financial officer)
/s/ R. Scott Meyers	Chief Accounting Officer	May 18, 2009
R. Scott Meyers	Petroleum Development Corporation
	Managing General Partner of the Registrant
	(Principal accounting officer)

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