Rockies Region 2006 Limited Partnership 10-Q 2008 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

FORM 10-Q

T Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, 2008

OR

£ Transition Report Pursuant to Section 13 of 15(d) of the Securities Exchange Act of 1934

For the transition period from   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.)

120 Genesis Boulevard

Bridgeport, West Virginia  26330

(Address of principal executive offices and zip code)

(304) 842-3597

(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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes T      No £

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes £     No T

At July 31, 2008, the Partnership had 4,497 Investor Partner units outstanding.

ROCKIES REGION 2006 LIMITED PARTNERSHIP

TABLE OF CONTENTS

	PART I – FINANCIAL INFORMATION
Item 1.	Unaudited Condensed Financial Statements
	Balance Sheets	3
	Statements of Operations	4
	Statements of Cash Flows	5
	Notes to Unaudited Condensed Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	18
Item 4.	Controls and Procedures	19
	PART II – OTHER INFORMATION
Item 1.	Legal Proceedings	21
Item 1A.	Risk Factors	21
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	22
	SIGNATURES	23

2

PART 1 - FINANCIAL INFORMATION

Item 1.  Unaudited Condensed Financial Statements

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Condensed Balance Sheets

(Unaudited)

	June 30,			December 31,
	2008			2007*
Assets
Current assets:
Cash and cash equivalents	$	185,046		$	1,183,810
Accounts receivable - oil and gas sales		9,888,993			8,524,415
Oil inventory		42,524			-
Other assets		144,293			40,000
Total current assets		10,260,856			9,748,225
Oil and gas properties, successful efforts method		101,929,552			101,950,453
Less accumulated depreciation, depletion and amortization		(21,649,916	)		(15,882,832	)
Oil and gas properties, net		80,279,636			86,067,621
Other assets		98,376			-
Total Assets	$	90,638,868		$	95,815,846
Liabilities and Partners' Equity
Current liabilities:
Production taxes payable	$	642,710		$	598,390
Due to Managing General Partner-derivatives		5,618,216			1,080,170
Due to Managing General Partner-other		3,802,643			2,977,786
Total current liabilities		10,063,569			4,656,346
Due to Managing General Partner-derivatives, long-term		2,678,905			-
Due to Managing General Partner - other, long-term		98,376			-
Asset retirement obligations		790,738			775,652
Total liabilities		13,631,588			5,431,998
Commitments and Contingencies
Partners' equity:
Managing General Partner		23,556,674			28,539,072
Limited Partners - 4,497 units issued & outstanding		53,450,606			61,844,776
Total Partners' equity		77,007,280			90,383,848
Total Liabilities and Partners' Equity	$	90,638,868		$	95,815,846

*Derived from audited 2007 balance sheet.

See accompanying notes to unaudited condensed financial statements.

3

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Condensed Statements of Operations

(Unaudited)

	Three months ended June 30,						Six months ended June 30,
	2008			2007			2008			2007
Revenues:
Oil and gas sales	$	9,824,232		$	9,904,797		$	18,596,688		$	14,109,463
Oil and gas price risk management gain (loss), net		(4,633,739	)		80,000			(8,860,353	)		19,069
Total revenues		5,190,493			9,984,797			9,736,335			14,128,532
Operating costs and expenses:
Production and operating costs		1,632,902			1,544,329			3,222,155			2,284,592
Direct costs		155,298			19,536			375,745			40,957
Depreciation, depletion and amortization		2,753,489			4,778,643			5,767,084			6,800,185
Accretion of asset retirement obligations		9,399			9,847			19,092			18,298
Loss on impairment of oil and gas properties		-			1,310,409			-			2,445,617
Exploratory dry hole cost		48,531			3,150,266			48,531			6,545,476
Total operating costs and expenses		4,599,619			10,813,030			9,432,607			18,135,125
Income (loss) from operations		590,874			(828,233	)		303,728			(4,006,593	)
Gain on sale of leasehold		-			-			120,000			-
Interest income, net		29,464			47,712			59,871			55,057
		-			-			-			-
Net income (loss)	$	620,338		$	(780,521	)	$	483,599		$	(3,951,536	)
Net income (loss) allocated to Managing General Partner	$	229,525		$	(288,793	)	$	178,932		$	(1,462,068	)
Net income (loss) allocated to Investor Partners	$	390,813		$	(491,728	)	$	304,667		$	(2,489,468	)
Net income (loss) per Investor Partner unit	$	87		$	(109	)	$	68		$	(554	)

See accompanying notes to unaudited condensed financial statements.

4

ROCKIES REGION 2006 LIMITED PARTNERSHIP

Condensed Statements of Cash Flows

(Unaudited)

	Six month ended June 30,
	2008			2007
Cash flows from operating activities:
Net income (loss)	$	483,599		$	(3,951,536	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		5,767,084			6,800,185
Accretion of asset retirement obligations		19,092			18,298
Unrealized loss (gain) on derivative transactions		6,946,432			(14,498	)
Loss on impairment of oil and gas properties		-			2,445,617
Exploratory dry hole costs		48,531			6,545,476
Gain on sale of leaseholds		(120,000	)		-
Changes in operating assets and liabilities:
Accounts receivable oil and gas sales		(1,364,578	)		(8,952,419	)
Other assets		(104,293	)		-
Production taxes payable		44,320			588,721
Due to Managing General Partner - other		2,121,216			778,700
Net cash provided by operating activities		13,841,403			4,258,544
Cash flows from investing activities:
Proceeds from sale of leaseholds		120,000
Capital expenditures for oil and gas properties		(1,100,000	)		-
Net cash used in investing activities		(980,000	)		-
Cash flows from financing activities:
Distributions to Partners		(13,860,167	)		(4,255,017	)
Net cash used in financing activities		(13,860,167	)		(4,255,017	)
Net increase (decrease) in cash and cash equivalents		(998,764	)		3,527
Cash and cash equivalents, beginning of period		1,183,810			1,154,594
Cash and cash equivalents, end of period	$	185,046		$	1,158,121
Supplemental disclosure of non-cash activity:
Asset retirement obligation, with corresponding change to oil and gas properties	$	(4,006	)	$	395,626

  See accompanying notes to unaudited condensed financial statements.

5

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

June 30, 2008

(1) GENERAL

The Rockies Region 2006 Limited Partnership (the “Partnership”) was organized as a limited partnership on September 7, 2006, in accordance with the laws of the State of West Virginia for the purpose of engaging in the exploration and development of oil and gas properties and commenced business operations as of the date of organization.

Purchasers of partnership units subscribed to and fully paid for 47.25 units of limited partner interests and 4,449.78 units of additional general partner interests at $20,000 per unit.  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 thereupon became limited partners of the Partnership.  Petroleum Development Corporation (“PDC”) has been designated the Managing General Partner of the Partnership and has a 37% ownership in the Partnership. Generally, throughout the term of the Partnership, revenues, costs, and cash distributions are allocated 63% to the limited and additional general partners (collectively, the “Investor Partners”) which are shared on a per unit basis and 37% to the Managing General Partner.  During the six months ended June 30, 2008, PDC acquired 3.5 limited partner units.  As such, PDC 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.  The Partnership operates as a single business unit.

Basis of Presentation

The accompanying interim unaudited condensed financial statements have been prepared without audit in accordance with accounting principles generally accepted in the Unites 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 (“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 and six months ended June 30, 2008 and 2007, 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, 2007, was derived from audited financial statements, but as indicated above, may not include all disclosures required by accounting principles generally accepted in the U.S.  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, 2007, as filed with the SEC on April 7, 2008.

(2) RECENT ACCOUNTING STANDARDS

Recently Adopted Accounting Standards

We adopted the provisions of Statement of Financial Accounting Standards ("SFAS") No. 157, Fair Value Measurements, effective January 1, 2008.  SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. SFAS No. 157 applies broadly to financial and non-financial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.  In February 2008, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position “FSP”, No. 157-2, Effective Date of FASB Statement No. 157, which delays the effective date of SFAS No. 157 by one year (to January 1, 2009) for non-financial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually).  Non-financial assets and liabilities for which we have not applied the provisions of SFAS No. 157 include those initially measured at fair value, including our asset retirement obligations.  As of the adoption date, we have applied the provisions of SFAS No. 157 to our recurring measurements and the impact was not material to our underlying fair values and no amounts were recorded relative to the cumulative effect of a change in accounting.  We are currently evaluating the potential effect that the nonfinancial assets and liabilities provisions of SFAS No. 157 will have on our financial statements when adopted in 2009.  See Note 5 for further details on our fair value measurements.

6

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities.  SFAS No. 159 permits entities to choose to measure, at fair value, many financial instruments and certain other items that are not currently required to be measured at fair value.  The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions.  SFAS No. 159 establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities.  The statement will be effective as of the beginning of an entity's first fiscal year beginning after November 15, 2007.  As of June 30, 2008, we had not elected, nor do we intend, to measure additional financial assets and liabilities at fair value.

In April 2007, the FASB issued FSP No. 39-1, Amendment of FASB Interpretation No. 39 ("FIN No. 39-1'), to amend certain portions of Interpretation 39.  FIN No. 39-1 replaces the terms "conditional contracts" and "exchange contracts" in Interpretation 39 with the term "derivative instruments" as defined in Statement 133.  FIN No. 39-1 also amends Interpretation 39 to allow for the offsetting of fair value amounts for the right to reclaim cash collateral or receivable, or the obligation to return cash collateral or payable, arising from the same master netting arrangement as the derivative instruments.  FIN No. 39-1 applies to fiscal years beginning after November 15, 2007, with early adoption permitted.  The January 1, 2008 adoption of FSP FIN 39-1 had no impact on our financial statements.

Recently Issued Accounting Standards

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—An Amendment of FASB Statement No. 133, which changes the disclosure requirements for derivative instruments and hedging activities.  Enhanced disclosures are required to provide information about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.  SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged.  As SFAS No. 161 is disclosure related, we do not expect its adoption to have a material impact on our financial statements.

(3) TRANSACTIONS WITH MANAGING GENERAL PARTNER AND AFFILIATES

The Managing General Partner transacts business on behalf of the Partnership.  Revenues and other cash inflows received on behalf of the Partnership are distributed to the Partners net of (after deducting) corresponding operating costs and other cash outflows incurred on behalf of the Partnership.  Undistributed oil and gas revenues and corresponding production taxes, are recorded on the balance sheet under the captions “Accounts receivable-oil and gas sales” and “Production taxes payable” respectively.  The fair value of the Partnership’s portion of unexpired derivative instruments is recorded on the balance sheet under the caption “Due from the Managing General Partner – derivatives” in the case of net unrealized gains or “Due to  Managing General Partner – derivatives” in the case of net unrealized losses.  All other unsettled transactions between the Partnership and the Managing General Partner are recorded net on the balance sheet under the caption “Due to or from Managing General Partner - other.”

During the three and six months ended June 30, 2008, the Partnership paid to the Managing General Partner $166,117 and $332,890, respectively, for well operation fees and $2,619,220 and $5,161,330, respectively, in Managing General Partner equity cash distributions.  For the three month period ended June 30, 2007, the Partnership paid to the Managing General Partner $54,608 as reimbursement for well operation fees and $1,574,356 in equity cash distributions.  There were no reimbursements or cash distributions during the quarter ended March 31, 2007.   In addition, as an investor partner, PDC received $3,471 and $5,197 in equity cash distributions during the three and six month periods ended June 30, 2008.

7

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

(4) DERIVATIVE FINANCIAL INSTRUMENTS

The Managing General Partner utilizes commodity-based derivative instruments, entered into on behalf of the Partnership, to manage a portion of the Partnership’s exposure to price risk from oil and natural gas sales.  These instruments consist of Colorado Interstate Gas index “CIG” -based contracts for Colorado natural gas production and NYMEX – based swaps for our Colorado oil production. These derivative instruments have the effect of locking in for specified periods (at predetermined prices or ranges of prices) the prices the Managing General Partner receives for the volume of oil and natural gas to which the derivative relates.

The Partnership accounts for derivative financial instruments in accordance with Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Certain Hedging Activities, as amended.  Our derivative instruments do not qualify for use of hedge accounting under the provisions of SFAS No. 133.  Accordingly, all derivative instruments are recognized as either assets or liabilities on the accompanying condensed balance sheets at fair value and changes in the derivatives' fair values are recorded on a net basis in the accompanying condensed statements of operations in oil and gas price risk management gain (loss), net.

The Partnership is exposed to the effect of market fluctuations in the prices of oil and natural gas as they relate to our 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 Partnership employs established policies and procedures to manage the risks associated with these market fluctuations using commodity derivatives.  The Partnership’s policy prohibits the use of oil and natural gas derivative instruments for speculative purposes.

Economic Hedging 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 Gereral Partner has entered into various derivative instruments on behalf of the Partnership. As of June 30, 2008, the Partnership’s oil and natural gas derivative instruments were comprised of swaps and collars.  These instruments generally consist of Colorado Interstate Gas Index ("CIG") -based contracts for Colorado gas production and NYMEX-based swaps for our Colorado oil production.

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

· Collars contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the fixed put strike price, we receive the fixed price and pay the market price.  If the market price is between the call and the put strike price, no payments are due either party.

We purchase collars and set fixed-price swaps for our production to protect against price declines in future periods while retaining some of the benefits of price increases.

While these derivatives are structured to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price changes in the physical market.

8

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table summarizes our share of open derivative positions held by the Managing General Partner as of June 30, 2008.

	Open Derivative Positions as of June 30, 2008
	Short-term			Long-term			Total
Natural gas floors	$	116,818		$	173,956		$	290,774
Natural gas ceilings		(432,800	)		(11,113	)		(443,913	)
Natural gas swaps		(2,879,952	)		(157,820	)		(3,037,772	)
Oil swaps		(2,422,282	)		(2,683,927	)		(5,106,209	)
Total	$	(5,618,216	)	$	(2,678,904	)	$	(8,297,121	)
The maximum term for the derivative contracts listed above is 30 months.

The following table identifies the changes in the fair value of commodity based derivatives as reflected in the statements of operations:

	Three months ended June 30,					Six months ended June 30,
	2008			2007		2008			2007
Realized gain (loss)
Oil	$	(452,252	)	$	-	$	(634,471	)	$	-
Natural gas		(1,150,511	)		4,571		(1,279,450	)		4,571
Total realized gain (loss)		(1,602,763	)		4,571		(1,913,921	)		4,571
Unrealized gain (loss)		(3,030,976	)		75,429		(6,946,432	)		14,498
Oil and gas price risk management gain (loss), net	$	(4,633,739	)	$	80,000	$	(8,860,353	)	$	19,069

(5) FAIR VALUE MEASUREMENTS

As described above in Note 2, in September 2006, the FASB issued SFAS No. 157, Fair Value Measurements.  We adopted the provisions of SFAS No. 157 effective January 1, 2008.

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

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

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

Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.  Instruments included in Level 3 consist of our commodity derivatives for CIG based natural gas swaps, oil swaps, and oil and natural gas options.

Determination of fair value.  We measure fair value based upon quoted market prices, where available.  Our 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.  Our valuation determination also gives consideration to our nonperformance risk on our own liabilities as well as the credit standing of our counterparties.  Furthermore, while we believe 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.

9

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

SFAS No. 157 requires fair value measurements to be separately disclosed by level within the fair value hierarchy and requires a separate reconciliation of fair value measurements categorized as Level 3.  The following table presents, for each hierarchy level our assets and liabilities including both current and non-current portions, measured at fair value on a recurring basis as of June 30, 2008:

	Level 1		Level 2		Level 3			Total
Liabilities:
Commodity based derivatives	$	-	$	-	$	(8,297,121	)	$	(8,297,121	)
Net fair value of commodity based derivatives	$	-	$	-	$	(8,297,121	)	$	(8,297,121	)

The following table sets forth a reconciliation of our Level 3 fair value measurements:

	Three months			Six months
	Ended			Ended
	June 30, 2008			June 30, 2008
Fair value, beginning of period	$	(4,652,086	)	$	(1,080,170	)
Realized and unrealized losses included in Oil and gas price risk management gain (loss), net		(4,633,739	)		(8,860,353	)
Purchases, sales, issuances and settlements, net		988,704			1,643,402
Fair value, end of period	$	(8,297,121	)	$	(8,297,121	)

(6) COMMITMENTS AND CONTINGENCIES

Royalty Litigation.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 Company in the District Court, Weld County, Colorado alleging that we underpaid royalties on natural gas produced from wells operated by us in the State of Colorado (the "Droegemueller Action").  The plaintiff seeks declaratory relief and to recover an unspecified amount of compensation for underpayment of royalties paid by us pursuant to leases.  We removed the case to Federal Court on June 28, 2007.  The court approved a stay in proceedings until September 22, 2008 while the parties pursue mediation of the matter.  Based on the mediation held on May 28, 2008, and subsequent negotiations, we have accrued $24,000 for this potential liability as of June 30, 2008. While we are unable to predict the ultimate outcome of this suit, we believe that after consideration of the reserve discussed above, the ultimate outcome of the proceedings will not have a material adverse effect on our financial condition, results of operations or cash flows.

Derivative Contracts.  We would be exposed to oil and natural gas price fluctuations on underlying purchase and sale contracts should the counterparties to our derivative instruments not perform.  Nonperformance is not anticipated.  We have had no counterparty default losses.

10

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

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

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, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements.  These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected.  Among those risks, trends and uncertainties are our estimates of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in successfully drilling productive wells and in prospect development and property acquisitions and in projecting future rates of production, the timing of development expenditures and drilling of wells, our ability to sell our produced natural gas and oil and the prices we receive for  production, our ability to comply with changes in federal, state, local, and other laws and regulations, including environmental policies, the significant fluctuations in the oil and gas price environment and the Partnership’s ability to meet our price risk management objectives, and the operating hazards inherent to the oil and gas business.  In particular, careful consideration should be given to cautionary statements made in this Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2007, and our other SEC filings and public disclosures.  We undertake no duty to update or revise these forward-looking statements.

Overview

The results of operations for the three and six months ended June 30, 2008, were significantly impacted by record high oil and gas prices, which benefited the Partnership in terms of oil and gas sales and cash flows from operating activities, but also resulted in significant realized and unrealized oil and gas price risk management losses.  See Oil and gas price risk management gain (loss), net discussion below for a detailed discussion of realized and unrealized losses on oil and gas derivative activity.  Operating results for the three and six months ended June 30, 2007, were significantly impacted by charges for impairment of oil and gas properties and exploratory dry hole costs.

Oil and gas production continue to follow an anticipated curve line for wells in the Colorado region, increasing each quarter as wells were brought into production from December 2006 through September 30, 2007, at which time all of the Partnership’s 91 wells were producing, and declining each quarter thereafter.  During this same time period, as anticipated for wells in the Colorado region, oil production as a percentage of total production (measured in Mcfe’s) decreased steadily from 66% during the first quarter of production to 25% during the most recent quarter.

11

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Results of Operations

The following table presents significant operational information of the Partnership for the three and six months periods ended June 30, 2008 and 2007:

	Three months ended June 30,									Six months ended June 30,
(Unaudited)	2008			2007			Change			2008			2007			Change
Number of Producing Wells (end of period)		91			64			42	%		91			64			42	%
Production:
Natural gas (Mcf)		664,902			848,953			-22	%		1,348,786			1,122,284			20	%
Oil (Bbl)		37,733			104,673			-64	%		83,720			163,811			-49	%
Natural gas equivalents (Mcfe)		891,300			1,476,991			-40	%		1,851,106			2,105,150			-12	%
Average Selling Price:
Natural gas (per Mcf)	$	8.44		$	5.03			68	%	$	7.77		$	5.17			50	%
Oil (per Bbl)	$	111.57		$	53.86			107	%	$	96.99		$	50.74			91	%
Natural gas equivalents (per Mcfe)	$	11.02		$	6.71			64	%	$	10.05		$	6.70			50	%
Average Selling Price (including realized gain or loss on derivatives)
Natural gas (per Mcf)	$	6.71		$	5.03			33	%	$	6.82		$	5.17			32	%
Oil (per Bbl)	$	99.58		$	53.86			85	%	$	89.41		$	50.74			76	%
Natural gas equivalents (per Mcfe)	$	9.22		$	6.71			37	%	$	9.01		$	6.70			34	%
Average Costs (per Mcfe):
Production and operating costs	$	1.83		$	1.05			75	%	$	1.74		$	1.09			60	%
Depreciation, depletion and amortization	$	3.09		$	3.24			-5	%	$	3.12		$	3.23			-4	%
Revenues:
Natural gas sales	$	5,614,538		$	4,267,622			32	%	$	10,476,597		$	5,797,930			81	%
Oil sales		4,209,694			5,637,175			-25	%		8,120,091			8,311,533			-2	%
Oil and gas sales		9,824,232			9,904,797			-1	%		18,596,688			14,109,463			32	%
Oil and gas price risk management gain (loss) , net		(4,633,739	)		80,000			***			(8,860,353	)		19,069			***
Total revenues		5,190,493			9,984,797			-48	%		9,736,335			14,128,532			-31	%
Costs and Expenses:
Production and operating costs		1,632,902			1,544,329			6	%		3,222,155			2,284,592			41	%
Direct costs		155,298			19,536			***			375,745			40,957			***
Depreciation, depletion and amortization		2,753,489			4,778,643			-42	%		5,767,084			6,800,185			-15	%
Accretion of asset retirement obligation		9,399			9,847			-5	%		19,092			18,298			4	%
Loss on impairment of oil and gas properties		-			1,310,409			-100	%		-			2,445,617			-100	%
Exploratory dry hole costs		48,531			3,150,266			-98	%		48,531			6,545,476			-99	%
Total costs and expenses		4,599,619			10,813,030			-57	%		9,432,607			18,135,125			-48	%
Income (loss) from operations		590,874			(828,233	)		-171	%		303,728			(4,006,593	)		-108	%
Gain on sale of leasehold		-			-						120,000			-
Interest income - net		29,464			47,712			-38	%		59,871			55,057			9	%
Net income (loss)	$	620,338		$	(780,521	)		-179	%	$	483,599		$	(3,951,536	)		-112	%
Cash distributions	$	7,078,977		$	4,255,017			66	%	$	13,860,167		$	4,255,017			226	%

***Represents percentages in excess of 250%

Definitions

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

· Mcf – One thousand cubic feet

· Mcfe – One thousand cubic feet of gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content.

12

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Oil and Gas Sales

Oil and gas sales decreased only slightly from $9.9 million for the three month period ended June 30, 2007 to $9.8 million this year.  The net change is comprised of decreases of $4.6 million attributable to 40% lower volumes  offset by increases attributable to higher prices, $2.2 million attributable to oil and $2.3 million attributable to gas.

The decrease in volume for the comparative six month period is not as severe as the three month period as there were fewer wells in production during the first quarter of 2007 than in later periods.  The 12% decrease in volume resulted in a $3.0 million reduction in sales. This decrease was offset by a 50% increase in gas prices and a 91% increase in oil prices resulting in increased sales of $3.9 million and $3.5 million respectively.

Currently since oil is selling at a higher multiple of gas on a mcfe basis (12.5 to 1, relative to energy content (6 to 1)), a decrease in oil production has a greater impact on oil and gas sales than does a similar drop in natural gas production.

Oil and Gas Pricing:Financial results depend upon many factors, particularly the price of oil and gas and our ability to market our production effectively.  Oil and gas prices have been among the most volatile of all commodity prices.  These price variations have a material impact on our financial results.  Oil and gas prices also vary by region and locality, depending upon the distance to markets, and the supply and demand relationships in that region or locality.  This can be especially true in the Rocky Mountain Region in which all of the partnership wells are located.  The combination of increased drilling activity and the lack of local markets have resulted in a local market oversupply situation from time to time.  Such a situation existed in the Rocky Mountain Region during 2007, with production exceeding the local market demand and pipeline capacity to non-local markets.  The result, beginning in the second quarter of 2007 and continuing through and into the fourth quarter of 2007, was a decrease in the price of Rocky Mountain natural gas compared to the New York Mercantile Exchange (“NYMEX”) price.  The expansion in January 2008 of the Rockies Express pipeline (“REX”), a major interstate pipeline constructed and operated by a non-affiliated entity, resulted in a narrowing of the NYMEX/Colorado Interstate Gas (“CIG”) price differential from November 2007 into the first quarter of 2008.  The differential has widened again during the current three month period to an average below NYMEX of $2.45.  For the remainder of 2008, the differential is currently estimated at $4.22.   Once the third phase of the expansion of the REX is completed in 2009, the pipeline capacity is expected to increase by 64% to 1.8 Bcf/per day of natural gas from the region.  Like most producers in the region, we rely on major interstate pipeline companies to construct these facilities to increase pipeline capacity, rendering the timing and availability of these facilities beyond our control.

Oil pricing is also driven strongly by supply and demand relationships.  In the Rocky Mountain Region in 2007, and in the first quarter of 2008, the oil prices were below the NYMEX oil market due to supply competition from Rocky Mountain and Canadian oil that has driven down market prices.

The price we receive for a large portion of the natural gas produced in the Rocky Mountain Region is based on a market basket of prices, which may include some gas sold at the CIG, Index prices and some sold at mid-continent prices.  The CIG Index, and other indices for production delivered to other Rocky Mountain pipelines, has historically been less than the price received for natural gas produced in the eastern regions, which is NYMEX, based.

13

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Oil and gas price risk management gain (loss), net

The Managing General Partner uses oil and natural gas commodity derivative instruments to manage price risk for itself as well as its sponsored drilling partnerships including the Partnership.  As volumes produced change, the mix between the Partnership and the other participants will change.

The following table presents the primary composition of oil and gas price risk management gain (loss), net:

	Three months ended June 30,					Six months ended June 30,
	2008			2007		2008			2007
Realized gain (loss)
Oil	$	(452,252	)	$	-	$	(634,471	)	$	-
Natural gas		(1,150,511	)		4,571		(1,279,450	)		4,571
Total realized gain (loss)		(1,602,763	)		4,571		(1,913,921	)		4,571
Unrealized gain (loss)		(3,030,976	)		75,429		(6,946,432	)		14,498
Oil and gas price risk management gain (loss), net	$	(4,633,739	)	$	80,000	$	(8,860,353	)	$	19,069

The rapid increases during the first half of 2008 to record high oil prices and sharp increases in natural gas prices from December 31, 2007, along with our increased use of derivative contracts and specifically more fixed price swaps caused the increase in realized and unrealized losses in oil and gas price risk management gain (loss), net.  The $6.9 million in unrealized losses for the six months ended June 30, 2008, is the fair value of the derivative positions as of June 30, 2008, less the related unrealized amounts recorded in prior period.  The unrealized loss is a non-cash item and there will be further gains or losses as prices increase or decrease until the positions are closed.  While the required accounting treatment for derivatives that do not qualify for hedge accounting treatment under SFAS No. 133 results in significant swings in value and resulting gains and losses for reporting purposes over the life of the derivatives, the combination of the settled derivative contracts and the revenue received from the oil and gas sales at delivery are expected to result in a more predictable cash flow stream than would the sales contracts without the associated derivatives.  The price of both oil and natural gas has declined significantly since June 30, 2008, and if the prices remain at current levels or continue to decline, we expect to experience unrealized derivative gains for the third quarter of 2008.

Oil and Gas Derivative Activities.  Because of uncertainty surrounding natural gas and oil prices we have used various derivative instruments to manage some of the impact of fluctuations in prices.  Through December 2010, we have in place a series of floors, ceilings and fixed price swaps on a portion of our natural gas and oil production.  Under the arrangements, if the applicable index rises above the ceiling price, we pay the counterparty; however, if the index drops below the floor, the counterparty pays us.

14

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table sets forth our derivative positions in effect as of August 8, 2008, on the Partnership's share of production by area.

			Floors				Ceilings				Swaps (Fixed Prices)
Commodity/ Index/ Area	Month Set	Month	Monthly Quantity (Gas -MMbtu Oil -Bbls)		Price		Monthly Quantity (Gas -MMbtu Oil -Bbls)		Price		Monthly Quantity (Gas-MMbtu Oil -Bbls)		Price
Natural Gas - (CIG)
Piceance Basin
	Feb-08	Jul 08 - Oct 08		-	$	-		-	$	-		60,150	$	7.05
	Jan-08	Jul 08 - Oct 08		-		-		-		-		50,526		6.54
	Apr-08	Nov 08 - Mar 09		-		-		-		-		45,714		7.76
	Jul-08	Nov 08 - Mar 09		-		-		-		-		27,268		8.52
	Feb-08	Nov 08 - Mar 09		-		-		-		-		27,268		8.18
	Jan-08	Apr 09 - Oct 09		45,714		5.75		45,714		8.75		-		-
	Mar-08	Apr 09 - Oct 09		44,912		5.75		44,912		9.05		-		-
	Jul-08	Nov 09 - Mar 10		-		-		-		-		36,090		9.20
	Jul-08	Nov 09 - Mar 10		51,328		7.50		51,328		11.40		-		-
Wattenberg Field
	Feb-08	Jul 08 - Oct 08		-		-		-		-		21,420		7.05
	Jan-08	Jul 08 - Oct 08		-		-		-		-		13,090		6.54
	Apr-08	Nov 08 - Mar 09		-		-		-		-		13,090		7.76
	Jul-08	Nov 08 - Mar 09		-		-		-		-		7,735		8.52
	Feb-08	Nov 08 - Mar 09		-		-		-		-		7,735		8.18
	Jan-08	Apr 09 - Oct 09		13,090		5.75		13,090		8.75		-		-
	Mar-08	Apr 09 - Oct 09		11,900		5.75		11,900		9.05		-		-
	Jul-08	Nov 09 - Mar 10		-		-		-		-		11,900		9.20
	Jul-08	Nov 09 - Mar 10		16,065		7.50		16,065		11.40		-		-
Oil - NYMEX
Wattenberg Field
	Oct-07	Jul 08 - Dec 08		-		-		-		-		2,609		84.20
	May-08	Jul 08 - Dec 08		-		-		-		-		1,966		108.05
	Jan-08	Jan 09 - Dec 09		-		-		-		-		1,630		84.90
	Jan-08	Jan 09 - Dec 09		-		-		-		-		1,630		85.40
	May-08	Jan 09 - Dec 09		-		-		-		-		652		117.35
	May-08	Jan 10 - Dec 10		-		-		-		-		1,630		92.74
	May-08	Jan 10 - Dec 10		-		-		-		-		1,630		93.17

The Managing General Partner uses oil and natural gas commodity derivative instruments to manage price risk for itself as well as the Partnership.  The Managing General Partner sets these instruments for itself and the Partnership jointly by area of operation.  As volumes produced change, the mix between PDC and the Partnership will change.  The volumes in the above table reflect the total volumes hedged for the Partnership by area of operation.  The above table reflects such revisions necessary to present the Partnership’s positions in effect as of August 8, 2008.

Costs and Expenses

Production and operating costs includes production taxes and transportation costs which generally tend to fluctuate with changes in oil and gas sales, per well operating fees paid to the Managing General Partner and other direct well charges.  Accordingly, higher oil and gas prices caused production and operating cost per Mcfe to increase from $1.05 per Mcfe for the first quarter of 2007 to $1.83 per Mcfe for the first quarter of 2008 and from $1.09 per Mcfe for the first half of 2007 to $1.74 for the first half of 2008.  Production and operating costs as a percentage of oil and gas sales have remained between 16% -19% in each of the last six quarters.

Depreciation, depletion and amortization (DD&A) results solely from the depletion and amortization of well equipment and lease costs and accordingly changes in relative concert with changes in the level of production.   The average cost per Mcfe as for the three and six months ended June 30, 2008 was $3.09 and $3.12 respectively compared to $3.24 and $3.23 for the same periods a year ago.   The lower rate in the current periods is attributable primarily to changes in reserve estimates at December 31, 2007.  The upward revision in our reserve report at December 31, 2007, due to higher commodity pricing partially offset by increased operating costs, lowered our DD&A cost per Mcfe.  

15

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Direct costs include the Partnership’s reimbursement to the Managing General Partners for administrative costs incurred on our behalf for administrative and professional fees such as legal expenses, audit fees, income tax preparation fees and engineering fees for reserve reports.  Such costs were low during the first two quarters of 2007 as the Partnership was not yet subject to reporting requirements and therefore did not incur significant auditing costs until the third and fourth quarter of 2007.  Since the fourth quarter of 2007, the Partnership has recorded its portion of legal costs and royalty litigation provision relating to certain legal matters as further discussed in Note 5, Commitments and Contingencies, to the accompanying unaudited condensed financial statements.

The Partnership concluded its drilling activities in 2007 and accordingly will not incur exploration costs beyond 2007, nor did the Partnership incur impairment charges during the first half of 2008.  During the quarter ended March 31, 2008, the Managing General Partner sold two of the Partnership’s Wattenberg wells previously determined to be exploratory dry holes.  Accordingly, the Partnership recognized a gain on the sale of leaseholds equal to the entire $120,000 proceeds which were received during the quarter ended June 30, 2008.

Liquidity and Capital Resources

The Partnership had working capital of $0.2 million at June 30, 2008 compared to $5.1 million at December 31, 2007.  Adjusting for the unrealized losses on derivative contracts expiring in less than twelve months, the respective balances were $5.8 million and $6.2 million which generally represents the receivables from oil and gas sales for the preceding three months offset by corresponding production taxes payable and accrued expenses for the same period.

As the Partnership completed its drilling activities as of December 31, 2007, the Partnership’s operations are expected to be conducted with available funds and revenues generated from oil and gas production activities.  Except for amounts that were due to the Managing General Partner as of December 31, 2007 and paid during the first quarter of 2008, no additional funds will be used at this time for drilling activities.  As such, the Partnership’s liquidity will be impacted by, among other factors, fluctuating oil and gas prices.  The Partnership initiated monthly cash distributions to investors in May 2007 and has distributed $34.5 million of operating cash flows through June 30, 2008.

Changes in market prices for oil and gas directly affect the level of our cash flow from operations.  While a decline in oil and natural gas prices would affect the amount of cash flow that would be generated from operations, we had oil and natural gas hedges in place, as of June 30, 2008, covering 31% of our expected oil production and 62% of our expected natural gas production for the remainder of 2008, thereby providing price certainty for a substantial portion of our 2008 cash flow.  Our current hedging 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.  Our oil and natural gas hedges as of June 30, 2008, are detailed in Note 4 Derivative Financial Instruments, to the accompanying unaudited condensed financial statements.

16

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Information related to the oil and gas reserves of the Partnership’s wells is discussed in detail in the partnership 2007 Form 10-K, Note 7 – Supplemental Reserve Information and Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Gas Reserves (Unaudited).

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.

Contractual Obligations and Contingent Commitments

The table below sets forth the Partnership's contractual obligations and contingent commitments as of June 30, 2008.

	Payments due by period
			Less						More
			than						than
	Total		1 Year		1-3 Years		3-5 years		5 years
Derivative obligations	$	8,297,121	$	5,618,216	$	2,678,905	$	-	$	-
Asset retirement obligations		790,738		-		-		-		790,738
Total	$	9,087,859	$	5,618,216	$	2,678,905	$	-	$	790,738

Commitments and Contingencies

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

Recent Accounting Standards

See Note 2, Recent Accounting Standards, to the accompanying unaudited condensed financial statements.

Critical Accounting Polices and Estimates

The preparation of the accompanying unaudited condensed financial statements in conformity with accounting principles generally accepted in the U.S. 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.

We believe that our accounting policies for revenue recognition, derivatives instruments, oil and 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, 2007, filed with the SEC on April 7, 2008.

17

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership's primary market risk exposure is commodity price risk.  This exposure is discussed in detail below:

See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operation, Critical Accounting Policies and Estimates-Accounting for Derivatives Contracts at Fair Value, of our 2007 Form 10-K for further discussion of the accounting for derivative contracts.

Commodity Price Risk

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

Derivative arrangements are entered into by the Managing General Partner on behalf of the Partnership and are reported on the Partnership’s balance sheet at fair value as a net short-term or long-term receivable from or payable to the Managing General Partner.  Changes in the fair value of the Partnership’s share of derivatives are recorded in the statement of operations.

Validation of a contract’s fair value is performed by the Managing General Partner, and while it uses common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values.

Economic Hedging Strategies

The results of the Partnership’s operations and operating cash flows are affected by changes in market prices for oil and gas. To mitigate a portion of the exposure to adverse market changes, the Managing General Partner has entered into various derivative instruments on behalf of the Partnership.  As of June 30, 2008, our oil and gas derivative instruments were comprised of collars and swaps.  These instruments generally consist of CIG-based contracts for Colorado gas production and NYMEX-based swaps for our Colorado oil production.

· For swap instruments, we receive a fixed price for the derivative contracts and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

· Collars contain a fixed floor price (put) and ceiling price (call).  If the market price exceeds the call strike price or falls below the fixed put strike price, we receive the fixed price and pay the market price.  If the market price is between the call and the put strike price, no payments are due either party.

The managing general partner purchases collars to protect against price declines in future periods.  While these derivatives are structured to reduce the Partnership's exposure to changes in price associated with the derivative commodity, they also limit the benefit the Partnership might otherwise have received from price changes in the physical market.

18

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

The following table presents monthly average NYMEX and CIG closing prices for oil and natural gas for the six months ended June 30, 2008, and the year ended December 31, 2007, as well as average sales prices we realized for the respective commodity.

	Six Months		Year
	Ended		Ended
	June 30, 2008		December 31, 2007
Average Index Closing Prices
Oil (per Barrel)
NYMEX	$	105.67	$	69.79
Natural Gas (per MMbtu)
NYMEX		9.48		6.89
CIG		7.72		3.97
Average Sale Price
Oil		96.99		58.55
Natural Gas		7.77		4.63

Based on a sensitivity analysis as of June 30, 2008, it was estimated that a 10% increase in oil and gas prices over the entire period for which we have derivatives currently in place would have resulted in an increase in unrealized losses of $3,055,000 and a 10% decrease in oil and gas prices would have resulted in a decrease in unrealized losses of $3,023,000.

See Note 3, Transactions with Managing General Partner and Affiliates and Note 4,  Derivative Financial Instruments to the accompanying unaudited condensed financial statements for additional disclosure regarding derivative instruments including, but not limited to, a summary of the open derivative positions as of June 30, 2008.

Disclosure of Limitations

Because the information above included only those exposures that exist at June 30, 2008, it does not consider those exposures or positions which could arise after that date.  As a result, the Partnership's ultimate realized gain or loss with respect to commodity price fluctuations depends on the future exposures that arise during the period, the Partnership's hedging strategies at the time and commodity prices at the time.

Item 4. 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.

As discussed in the Managing General Partner's 2007 Form 10-K, the Managing General Partner did not maintain effective controls as of December 31, 2007, over the (1) completeness, accuracy, validity and restricted access of certain key financial statement spreadsheets that support all significant balance sheet and income statement accounts and (2) policies and procedures, or personnel with sufficient technical expertise to record derivative activities in accordance with generally accepted accounting principles.

Evaluation of Disclosure Controls and Procedures

As of June 30, 2008, the Managing General Partner carried out an evaluation, under the supervision and with the participation of the Managing General Partner’s 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 Rule 13a-15(e) and 15d-15(e).  This evaluation considered the various processes carried out under the direction of the Managing General Partner's disclosure committee in an effort to ensure that information required to be disclosed in the Partnership's SEC reports filed or submitted under the Exchange Act are recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely discussion regarding required financial disclosure.

19

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Management of the Managing General Partner identified the following material weakness concerning the effectiveness of the Partnership’s internal controls over financial reporting as of June 30, 2008:

· The Partnership did not maintain effective controls to ensure the completeness, accuracy, and validity of a key financial statement spreadsheet that supports significant balance sheet and income statement accounts.  Specifically, the Partnership has inadequate controls over the Oil and Gas Production Accrual Spreadsheet concerning: 1) the integrity of the data used in the spreadsheet, 2) changes to spreadsheet functionality and the related approval process and documentation, and 3) management's review of the spreadsheets.  This spreadsheet is used in the financial close and reporting processes to generate financial data supporting a significant accrual process and to compile information to post entries into the general ledger system.  This control deficiency resulted in an adjustment to the Partnership's financial statements for the quarter ended June 30, 2008.  This control deficiency could result in a material misstatement of the annual or interim financial statements that would not be prevented or detected in a timely manner.

Based on results of this evaluation, the Managing General Partner’s Chief Executive Officer and Chief Financial Officer concluded that as a result of the material weaknesses cited above, their disclosure controls and procedures were not effective as of June 30, 2008.  Because of this material weakness, in addition to the Managing General Partner's material weaknesses cited in the Partnership's 2007 Form 10-K, the Managing General Partner performed additional procedures to ensure that the accompanying condensed financial statements as of and for the three and six months ended June 30, 2008, were fairly presented in all material respects in accordance with generally accepted accounting principles.

Changes in Internal Control over Financial Reporting

There were no changes in internal control over financial reporting in the second quarter of 2008.  During the first quarter of 2008, the Managing General Partner made the following changes in the Partnership's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect the Partnership's internal controls over financial reporting:

· During the first quarter of 2008, the Managing General Partner implemented the general ledger, accounts receivable, and joint interest billing modules as part of a new broader financial reporting system.  The Managing General Partner plans to implement additional new modules in 2008 to support the remaining processes and operations.  The Managing General Partner believes that the phased-in approach it is taking reduces the risks associated with the implementation. The Managing General Partner has taken the necessary steps to monitor and maintain appropriate internal controls during this period of change.  These steps include providing training related to business process changes and the financial reporting system software to individuals using the financial reporting system to carry out their job responsibilities as well as those who rely on the financial information.  The Managing General Partner anticipates that the implementation of the financial reporting system will strengthen the overall systems of internal controls due to enhanced automation and integration of related processes.  The Managing General Partner is modifying the design and documentation of internal control process and procedures relating to the new system to supplement and complement existing internal controls over financial reporting.   The system changes were undertaken to integrate systems and consolidate information, and were not undertaken in response to any actual or perceived deficiencies in the Partnership's internal control over financial reporting.  Testing of the controls related to these new systems is ongoing and is included in the scope of the Managing General Partner's assessment of the Partnership's internal control over financial reporting for 2008.

20

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

In August 2008, the Managing General Partner has made the following changes in the Partnership's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect internal controls over financial reporting:

· Created more in depth management review processes over the integrity of data and the changes made to data and formulas in material spreadsheets.

· Created detailed analytics to capture and ensure critical variances in the spreadsheet data are reviewed and corrected in a timely manner.

The Managing General Partner continues to evaluate the ongoing effectiveness and sustainability of these changes in internal control over financial reporting, and, as a result of the ongoing evaluation, may identify additional changes to improve internal control over financial reporting.  For additional information regarding the material weaknesses of the Managing General Partner, please refer to its Annual Report on Form 10-K for the year ended December 31, 2007, as referenced above.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Information regarding our legal proceedings can be found in Note 6, Commitments and Contingencies, to our accompanying unaudited condensed financial statements.

Item 1A. Risk Factors

The Partnership's faces many risks.  Factors that could materially adversely affect its business, financial condition, operating results and liquidity  are described Item 1A, Risk Factors, of the Partnership's amended report on Form 10-K for the year ended December 31, 2007, as filed with the Securities and Exchange Commission on April 7, 2008.  This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.  There have been no material changes from the risk factors previously disclosed in the Partnership's 2007 Form 10-K except the addition of third paragraph to the following risk factor.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

Our exploration, development and production are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon natural gas and oil wells.  Under these laws and regulations, we could also be liable for personal injuries, property damage and other damages.  Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal penalties.  Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects.

Part of the regulatory environment includes federal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing exploration and production activities.  In addition, our activities are subject to the regulation by natural gas and oil-producing states of conservation practices and protection of correlative rights.  These regulations affect our operations, increase the cost of exploration and production and limit the quantity of natural gas and oil that can be produced and sold.  A major risk inherent in our drilling plans is the need to obtain drilling permits from state and local authorities.  Delays in obtaining regulatory approvals, drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore on or develop our properties.  Additionally, the natural gas and oil regulatory environment could change in ways that might substantially increase our financial and managerial costs to comply with the requirements of these laws and regulations and, consequently, adversely affect our profitability.  Furthermore, these additional costs may put us at a competitive disadvantage compared to larger companies in the industry which can spread such additional costs over a greater number of wells and larger operating staff.

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ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

Illustrative of these risks, are regulations currently proposed by the State of Colorado which target the oil and gas industry.  These multi-faceted proposed regulations significantly enhance requirements regarding oil and gas permitting, environmental requirements, and wildlife protection.  The wildlife protection requirements, in particular, could require an intensive wildlife survey prior to any drilling, and may further entirely prohibit drilling for extended periods during certain wildlife breeding seasons.  Many landowners and energy companies are strenuously opposing these proposed regulatory changes, and it is impossible at this time to assess the form of the final regulations or the cost to our company.  Significant permitting delays and increased costs could result from any final regulations.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Item 5. Other Information

None.

Item 6. Exhibits.

Exhibit No.	Description
31.1	Certification by Chief Executive Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Chief Financial Officer of Petroleum Development Corporation, the Managing General Partner of the Partnership, pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Chief Executive Officer and Chief Financial Officer of Petroleum Development Corporation, the  Managing General Partner of the Partnership, pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

22

ROCKIES REGION 2006 LIMITED PARTNERSHIP

(A West Virginia Limited Partnership)

SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of 1934, the registrant has duly caused this registration statement 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

Chief Executive Officer and Chief Financial Officer

August 19, 2008

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	Chief Executive Officer and Chief Financial Officer	August 19, 2008
	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(Principal financial  officer)
/s/ Darwin L. Stump	Chief Accounting Officer	August 19, 2008
	Petroleum Development Corporation,
	Managing General Partner of the Registrant
	(Principal accounting officer)