Reef Global Energy VII, L.P. - FORM 10-Q

Attached files

file	filename
EX-32.2 - Reef Global Energy VII, L.P.	v202070_ex32-2.htm
EX-32.1 - Reef Global Energy VII, L.P.	v202070_ex32-1.htm
EX-31.1 - Reef Global Energy VII, L.P.	v202070_ex31-1.htm
EX-31.2 - Reef Global Energy VII, L.P.	v202070_ex31-2.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 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 September 30, 2010

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

For the Transition Period from ________ to ________

Commission File Number: 333-122935-02

REEF GLOBAL ENERGY VII, L.P.

(Exact name of registrant as specified in its charter)

Nevada		20-3963203
(State or other jurisdiction of		(I.R.S. employer
incorporation or organization)		identification no.)

1901 N. Central Expressway, Suite 300		75080-3610
Richardson, Texas		(Zip code)
(Address of principal executive offices)

(972)-437-6792

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 x No ¨

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

As of November 15, 2010, the registrant had 48.620 units of general partner interest held by the managing general partner, and 923.784 units of limited partner interest outstanding.

Reef Global Energy VII, L.P.

Form 10-Q Index

PART I — FINANCIAL INFORMATION

ITEM 1.	Financial Statements (Unaudited)	3
	Condensed Balance Sheets	3
	Condensed Statements of Operations	4
	Condensed Statements of Cash Flows	5
	Notes to Condensed Financial Statements	6

ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	9

ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	14

ITEM 4T.	Controls and Procedures	14

PART II — OTHER INFORMATION

ITEM 1.	Legal Proceedings	14

ITEM 1A.	Risk Factors	14

ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	15

ITEM 3.	Default Upon Senior Securities	15

ITEM 4.	(Removed and Reserved)	15

ITEM 5.	Other Information	15

ITEM 6.	Exhibits	15

Signatures		16

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Reef Global Energy VII, L.P.

Condensed Balance Sheets

	September 30,		December 31,
	2010		2009
	(Unaudited)

Assets

Current assets:
Cash and cash equivalents	$	63,442	$	63,432
Accounts receivable		—		3,471
Accounts receivable from affiliates		55,193		314,397
Total current assets		118,635		381,300

Oil and gas properties, full cost method of accounting:
Proved properties, net of accumulated depletion of $20,721,289 and $20,279,005		1,205,716		1,323,360
Net oil and gas properties		1,205,716		1,323,360

Total assets	$	1,324,351	$	1,704,660

Liabilities and partnership equity

Current liabilities:
Accounts payable	$	1,176	$	5,677
Accounts payable to affiliates		—		70,096
Total current liabilities		1,176		75,773

Long-term liabilities:
Asset retirement obligation		301,664		289,494
Total long-term liabilities		301,664		289,494

Partnership equity:
Limited partners		896,851		1,205,145
Managing general partner		124,660		134,248
Partnership equity		1,021,511		1,339,393

Total liabilities and partnership equity	$	1,324,351	$	1,704,660

See accompanying notes to condensed financial statements (unaudited).

Reef Global Energy VII, L.P.

Condensed Statements of Operations

(Unaudited)

	For the three months ended September 30,				For the nine months ended September 30,
	2010		2009		2010		2009

Revenues	$	357,456	$	336,209	$	1,138,543	$	1,015,127

Costs and expenses:
Lease operating expenses		99,776		67,811		212,501		236,272
Production taxes		24,971		14,109		19,473		61,772
Depreciation, depletion and amortization		145,983		125,549		442,284		494,991
Property impairment		—		—		—		566,482
Accretion of asset retirement obligation		4,126		4,262		12,170		14,403
General and administrative		45,067		69,000		211,798		232,125
Total costs and expenses		319,923		280,731		898,226		1,606,045

Income (loss) from operations		37,533		55,478		240,317		(590,918	)

Other income:
Interest income		46		113		171		1,358
Total other income		46		113		171		1,358

Net income (loss)	$	37,579	$	55,591	$	240,488	$	(589,560	)

Net income (loss) per limited partner unit	$	20.18	$	50.88	$	177.32	$	(633.26	)
Net income (loss) per managing general partner unit	$	389.43	$	176.65	$	1,577.09	$	(93.93	)

See accompanying notes to condensed financial statements (unaudited).

Reef Global Energy VII, L.P.

Condensed Statements of Cash Flows

(Unaudited)

	For the nine months ended September 30,
	2010			2009

Operating Activities
Net income (loss)	$	240,488		$	(589,560	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Adjustments for non-cash transactions:
Depreciation, depletion and amortization		442,284			494,991
Property impairment		—			566,482
Accretion of asset retirement obligation		12,170			14,403
Changes in operating assets and liabilities:
Accounts receivable		3,471			(456	)
Accounts receivable from affiliates		259,204			(92,494	)
Accounts payable		(4,501	)		45,140
Accounts payable to affiliates		(140,041	)		(290,339	)
Net cash provided by operating activities		813,075			148,167

Investing Activities
Property acquisition and development		(254,695	)		(182,346	)
Net cash used in investing activities		(254,695	)		(182,346	)

Financing Activities
Partner capital contributions		—			3,440
Offering costs		—			(270,000	)
Partner distributions		(558,370	)		(51,784	)
Net cash used in financing activities		(558,370	)		(318,344	)

Net increase (decrease) in cash and cash equivalents		10			(352,523	)
Cash and cash equivalents at beginning of period		63,432			444,655
Cash and cash equivalents at end of period	$	63,442		$	92,132

Supplemental disclosure of non-cash financing transactions
Property additions included in accounts payable to affiliates	$	(69,945	)	$	—
Offering costs included in accounts payable to affiliates	$	—		$	160,096

See accompanying notes to condensed financial statements (unaudited).

Reef Global Energy VII, L.P.

Notes to Condensed Financial Statements (unaudited)

September 30, 2010

1. Organization and Basis of Presentation

The financial statements of Reef Global Energy VII, L.P. (the “Partnership”) have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Certain information and footnote disclosure normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted pursuant to those rules and regulations. We have recorded all transactions and adjustments necessary to fairly present the financial statements included in this Quarterly Report on Form 10-Q (this “Quarterly Report”). The adjustments are normal and recurring. The following notes describe only the material changes in accounting policies, account details, or financial statement notes during the first nine months of 2010. Therefore, please read these condensed financial statements and notes to condensed financial statements together with the audited financial statements and notes to financial statements contained in the Partnership’s Annual Report on Form 10-K for the period ended December 31, 2009 (the “Annual Report”).

2. Summary of Accounting Policies

Oil and Gas Properties

The Partnership follows the full cost method of accounting for oil and gas properties. Under this method, all direct costs and certain indirect costs associated with acquisition of properties and successful as well as unsuccessful exploration and development activities are capitalized. Depreciation, depletion, and amortization of capitalized oil and gas properties and estimated future development costs, excluding unproved properties, are based on the unit-of-production method using estimated proved reserves, as determined by independent petroleum engineers. For these purposes, proved natural gas reserves are converted to equivalent barrels of crude oil at a rate of 6 Mcf to 1 Bbl.

In applying the full cost method at September 30, 2010, the Partnership performs a quarterly ceiling test on the capitalized costs of oil and gas properties, whereby the capitalized costs of oil and gas properties are limited to the sum of the estimated future net revenues from proved reserves using prices that are the 12-month un-weighted arithmetic average of the first-day-of-the-month price for crude oil and natural gas held constant and discounted at 10%, plus the lower of cost or estimated fair value of unproved properties, if any. If capitalized costs exceed the ceiling, an impairment loss is recognized for the amount by which the capitalized costs exceed the ceiling, and is shown as a reduction of oil and gas properties and as property impairment expense on the Partnership’s statements of operations. No gain or loss is recognized upon sale or disposition of oil and gas properties, unless such a sale would significantly alter the rate of depletion and amortization. During the three month periods ended September 30, 2010 and 2009, the Partnership recognized no property impairment expense of proved properties. During the nine month periods ended September 30, 2010 and 2009, the Partnership recognized property impairment expense of proved properties totaling $0 and $566,482, respectively.

Unproved properties consist of undeveloped leasehold interest in the Sand Dunes prospect (as discussed in Item 2 below). Investments in unproved properties are not depleted pending determination of the existence of proved reserves. Unproved properties are assessed for impairment quarterly as of the balance sheet date by considering the primary lease term, the holding period of the properties, geologic data obtained relating to the properties, and other drilling activity in the immediate area of the properties. Any impairment resulting from this quarterly assessment is reported as property impairment expense in the current period, as appropriate. The Partnership fully impaired its unproved properties during 2008 and has no plans to conduct any development operations on the leasehold interest in the Sand Dunes prospect.

Estimates of Proved Oil and Gas Reserves

Estimates of the Partnership’s proved reserves at September 30, 2010 and December 31, 2009 have been prepared and presented in accordance with new SEC rules and accounting standards. These new rules are effective for fiscal years ending on or after December 31, 2009, and require SEC reporting entities to prepare their reserve estimates using revised reserve definitions and revised pricing based upon the un-weighted arithmetic average of the first-day-of-the-month commodity prices over the preceding 12-month period and current costs. Future prices and costs may be materially higher or lower than these prices and costs, which would impact the estimate of reserves and future cash flows.

Reserves and their relation to estimated future net cash flows impact the Partnership’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. If proved reserve estimates decline, the rate at which depletion expense is recorded increases, reducing net income. A decline in estimated proved reserves and future cash flows also reduces the capitalized cost ceiling and may result in increased impairment expense.

Restoration, Removal, and Environmental Liabilities

The Partnership is subject to extensive Federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the environmental effects of the disposal or release of petroleum substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefit are expensed.

Liabilities for expenditures of a non-capital nature are recorded when environmental assessments and/or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted values unless the timing of cash payments for the liability or component is fixed or reliably determinable.

Asset retirement costs and liabilities associated with future site restoration and abandonment of long-lived assets are initially measured at fair value, which approximates the cost a third party would incur in performing the tasks necessary to retire such assets. The fair value is recognized in the financial statements as the present value of expected future cash expenditures for site restoration and abandonment. Subsequent to the initial measurement, the effect of the passage of time on the liability for the net asset retirement obligation (accretion expense) and the amortization of the asset retirement cost are recognized in the results of operations.

The following table summarizes the Partnership’s asset retirement obligation for the nine months ended September 30, 2010 and the year ended December 31, 2009.

	Nine months ended		Year Ended
	September 30, 2010		December 31, 2009
Beginning asset retirement obligation	$	289,494	$	270,772
Accretion expense		12,170		18,722
Ending asset retirement obligation	$	301,664	$	289,494

Fair Value of Financial Instruments

The estimated fair values for financial instruments have been determined at discrete points in time based on relevant market information. These estimates involve uncertainties and cannot be determined with precision. The estimated fair value of cash, accounts receivable and accounts payable approximates their carrying value due to their short-term nature.

Recently Adopted Accounting Pronouncements

Modernization of Oil and Gas Reporting

In January 2009, the SEC adopted a new rule related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. In addition to expanding the definition and disclosure requirements for crude oil and natural gas reserves, the new rule changes the requirements for determining quantities of crude oil and natural gas reserves. The new rule requires disclosure of crude oil and natural gas proved reserves by geographical area, using the unweighted arithmetic average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period prices, and allows the use of reliable technologies to estimate proved crude oil and natural gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserve volumes. In addition, in January 2010, the Financial Accounting Standards Board (“FASB”) issued guidance relating to crude oil and natural gas reserve estimation and disclosures to provide consistency with the new SEC rules. The Partnership adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. In April 2010, the FASB issued a further accounting standards update regarding extractive oil and gas industries to incorporate in accounting standards the revisions to Rule 4-10 of the SEC’s Regulation S-X. The amendment primarily consists of the addition and deletion of definitions of terms related to fossil fuel exploration and production arising from technology changes over the past several decades. The accounting guidance in Rule 4-10 did not change.

Fair Value Measurements

In January 2010, the FASB issued new guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. This guidance was adopted on January 1, 2010 for Level 1 and Level 2 fair value measurements and did not impact the Partnership’s operating results, financial position or cash flows or disclosures regarding the fair value of financial instruments.

3. Transactions with Affiliates

The Partnership has no employees. Reef Exploration, L.P. (“RELP”), an affiliate of Reef Oil & Gas Partners, L.P. (“Reef”), the managing general partner of the Partnership, employs a staff including geologists, petroleum engineers, landmen and accounting personnel who administer all of the Partnership’s operations. The Partnership reimburses RELP for technical and administrative services at cost. During the three month periods ended September 30, 2010 and 2009, the Partnership incurred technical services and administrative costs totaling $38,244 and $53,175, respectively. Of these amounts, $5,443 and $0 represent technical services costs capitalized as project costs, and $32,801 and $53,175 represent administrative costs included as general and administrative expenses. During the nine month periods ended September 30, 2010 and 2009, the Partnership incurred technical services and administrative costs totaling $144,321 and $178,926, respectively. Of these amounts, $7,844 and $1,207 represent technical services costs capitalized as project costs, and $136,477 and $177,719 represent administrative costs included as general and administrative expenses.

Reef contributed 1% of all leasehold, drilling, and completion costs when incurred during the drilling and completion phases of Partnership operations. Reef contributed $202,585 in connection with this obligation. Reef also purchased 5% of the Partnership units and paid 5% of the 99% of these costs paid by the unit holders (4.95%). Reef has had no remaining obligations related to these additional costs since December 31, 2009.

RELP processes joint interest billings and revenue payments on behalf of the Partnership. At September 30, 2010 and December 31, 2009, RELP owed the Partnership $55,193 and $314,397, respectively, for net revenues processed in excess of joint interest and technical and administrative charges. The cash associated with net revenues processed by RELP is normally received by RELP from oil and gas purchasers 30-60 days after the end of the month to which the revenues pertain.

Accounts payable to affiliates at December 31, 2009 included $70,096 for the unpaid portion of the 15% management fee due to Reef for organization and offering costs, including sales commissions. The management fee was payable in two parts. Reef initially received an amount not to exceed 13.5% of the total offering proceeds to recover actual commissions and organization and offering costs. The portion of the management fee in excess of actual commissions and organization and offering costs was paid to Reef from the oil and gas cash flows available for partner distributions, at a rate not to exceed $1 million per year. The Partnership completed payment of the December 31, 2009 balance to Reef in February 2010.

4. Commitments and Contingencies

The Partnership is not currently involved in any legal proceedings.

5. Partnership Equity

Information regarding the number of units outstanding and the net income per type of Partnership unit for the three and nine month periods ended September 30, 2010 is detailed below:

For the three months ended September 30, 2010

Type of Unit	Number of Units		Net income		Net income per unit
Managing general partner units		48.620	$	18,934	$	389.43
Limited partner units		923.783		18,645	$	20.18
Total		972.403	$	37,579

For the nine months ended September 30, 2010

Type of Unit	Number of Units		Net income		Net income per unit
Managing general partner units		48.620	$	76,678	$	1,577.09
Limited partner units		923.783		163,810	$	177.32
Total		972.403	$	240,488

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

The following is a discussion of the Partnership’s financial condition, results of operations, liquidity and capital resources. This discussion should be read in conjunction with our financial statements and the related notes thereto, included in the Annual Report.

This Quarterly Report contains forward-looking statements that involve risks and uncertainties. You should exercise extreme caution with respect to all forward-looking statements made in this Quarterly Report. Specifically, the following statements are forward-looking:

statements regarding the state of the oil and gas industry and the opportunity to profit within the oil and gas industry, competition, pricing, level of production, or the regulations that may affect the Partnership;

statements regarding the plans and objectives of Reef for future operations, including, without limitation, the uses of Partnership funds and the size and nature of the costs the Partnership expects to incur and people and services the Partnership may employ;

any statements using the words “anticipate,” “believe,” “estimate,” “expect” and similar such phrases or words; and

any statements of other than historical fact.

Reef believes that it is important to communicate its future expectations to the partners. Forward-looking statements reflect the current view of management with respect to future events and are subject to numerous risks, uncertainties and assumptions, including, without limitation, the risk factors listed in the section captioned “RISK FACTORS” contained in the Partnership’s Annual Report. Although Reef believes that the expectations reflected in such forward-looking statements are reasonable, Reef can give no assurance that such expectations will prove to have been correct. Should any one or more of these or other risks or uncertainties materialize or should any underlying assumptions prove incorrect, actual results are likely to vary materially from those described herein. There can be no assurance that the projected results will occur, that these judgments or assumptions will prove correct or that unforeseen developments will not occur.

Reef does not intend to update its forward-looking statements. All subsequent written and oral forward-looking statements attributable to Reef or persons acting on its behalf are expressly qualified in their entirety by the applicable cautionary statements.

Overview

Reef Global Energy VII, L.P. is a Nevada limited partnership formed to acquire, explore, develop and produce crude oil, natural gas, and natural gas liquids for the benefit of its investor partners. The Partnership’s primary purposes are to generate revenues from the production of crude oil and natural gas, distribute cash flow to investors, and provide tax benefits to investors. The Partnership purchased working interests in five developmental prospects and participated in the drilling of ten successful developmental wells and three unsuccessful developmental wells on those prospects. All ten successful wells are productive at September 30, 2010. The Partnership purchased a working interest in the Sand Dunes developmental prospect in Eddy County, New Mexico, and has participated in the drilling of eight developmental wells on this prospect (see below). The Partnership purchased working interests in seven exploratory prospects and participated in the drilling of one successful exploratory well, six unsuccessful exploratory wells, and one successful developmental well on those prospects. The successful exploratory well ceased production during 2007. The Partnership has completed its drilling program of twenty-nine wells using the original capital raised by the Partnership. The final well completed drilling in February 2008 and was placed into production during May 2008. Subsequent to initial drilling operations, the Partnership is permitted to conduct additional drilling on existing Partnership prospects. Currently, the Partnership has no plans for additional drilling.

In this Quarterly Report, we use the term “successful” to refer to wells that are drilled, tested, and either capable of or actually producing in commercial quantities. We use the term “unsuccessful” to refer to wells that do not meet one or more of these criteria.

The Partnership participated in the drilling of eight developmental wells on the Sand Dunes prospect located in Eddy County, New Mexico during the fourth quarter of 2007 and the first quarter of 2008. Initial testing confirmed the presence of crude oil and natural gas in all eight wells. However, the field was temporarily shut-in because of the lack of electric service and because of the high cost of trucking offsite the salt water volumes associated with the production of the crude oil and natural gas from the wells. Electrical service to the eight Sand Dunes wells was connected in September 2008. Based upon initial testing, larger bottom hole pumps were placed below the well perforations in three of the wells and testing was resumed in late September 2008 to determine the three wells’ commercial productivity. Water continued to be trucked offsite, and RELP applied for and received a permit which would allow for the conversion of one of the existing eight Sand Dunes wells into a salt water disposal well. RELP also explored the possibility of drilling a ninth well as a salt water disposal well for the field. Testing results on two of the three wells were positive, and salt water production volumes declined as a result of pumping off the wells using the larger bottom hole pumps. However, the price of crude oil also declined at a rapid rate while testing was being conducted. In late December 2008, two of the three testing wells were shut-in again. Crude oil prices continued declining to a level below $40 per barrel. In February 2009, following a mechanical failure in the third testing well, RELP, as operator, shut-in the field. The eight wells cannot be commercially productive without efficient salt water disposal capabilities, and none of the options regarding salt water disposal were economically viable at first quarter 2009 commodity prices. As a result, as of December 31, 2008, the eight Sand Dunes wells were classified as unsuccessful.

Beginning with March 2009, oil prices increased from levels below $40 per barrel to between $60 and $70 per barrel by the third quarter of 2009. As a result of this increase in prices, in October 2009, Reef approved the conversion of one of the eight wells on the Sand Dunes development prospect located in Eddy County, New Mexico to a salt water disposal well. The conversion work on the well began in March 2010 and was completed during April 2010. Upon completion of the disposal facilities, the new disposal well became operational during August 2010. Based on updated testing performed on the disposal capacity of the converted well, it is expected that all of the remaining seven Sand Dunes wells will be able to be placed into production. During the third quarter of 2010, five wells were placed back on full-time production. The remaining two Sand Dune wells are expected to be placed back in production during the fourth quarter of 2010. The cost of the well conversion to this Partnership as of September 30, 2010 was approximately $186,000. This cost was paid for by the Partnership by retaining a portion of the funds normally paid out in distributions to the partners. There are 6,257 BBL of crude oil and 9,843 Mcf of natural gas reserves net to the Partnership’s interest for the five wells placed on full time production during the third quarter of 2010. Reserve estimates may be increased if additional wells are able to be placed on full-time production or if daily production rates increase.

The Partnership also owns interests in unproved property consisting of un-drilled leasehold interest (11 potential drilling locations) in the Sand Dunes prospect. The Partnership fully impaired this unproved property during the fourth quarter of 2008 based upon the eight already drilled Sand Dunes wells being classified as unsuccessful at December 31, 2008. The Partnership currently has no plans to conduct any drilling operations on this acreage.

Critical Accounting Policies

There have been no changes from the Critical Accounting Policies described in the Annual Report.

Liquidity and Capital Resources

The Partnership was funded with initial capital contributions totaling $24,127,769. Reef purchased 48.620 general partner units, or 5% of the total units sold, for $1,033,179. Investor partners purchased 741.001 units of general partner interest and 182.783 units of limited partner interest for $23,094,590. Reef also contributed $202,585 in connection with its obligation to pay 1% of all leasehold, drilling, and completion costs. Organization and offering costs totaled $3,464,188, leaving capital contributions of $20,866,166 available for Partnership activities. The Partnership expended $21,574,409 on prospect and property acquisitions, drilling and completion costs in connection with its participation in the drilling of twenty-nine wells and expended $137,512 on general and administrative expenses during its drilling and completion phase of operations. The Partnership has also expended $324,639 subsequent to its drilling and completion phase of operations on the Sand Dunes well conversion and other capital items. Expenditures in excess of available Partnership capital have been recovered from the cash flow from successful wells by reducing Partnership distributions. Any additional capital expenditures will also be recovered from cash flow by reducing Partnership distributions. The Partnership does not operate in any other industry segment, and operates solely in the United States.

The Partnership has working capital of $117,459 at September 30, 2010. Subsequent to expending the initial available Partnership capital contributions on prospect acquisitions and drilling and completion costs of Partnership wells, the Partnership’s working capital consists primarily of cash flows from productive properties utilized to pay cash distributions to investors.

Results of Operations

The following is a comparative discussion of the results of operations for the periods indicated. It should be read in conjunction with the condensed financial statements and the related notes to the condensed financial statements included in this Quarterly Report.

The following table provides information about sales volumes and crude oil and natural gas prices for the periods indicated. Equivalent barrels of oil (“EBO”) are computed by converting 6 Mcf of natural gas to 1 barrel of oil.

	For the three months ended September 30,				For the nine months ended September 30,
	2010		2009		2010		2009
Sales volumes:
Crude oil (Barrels)		3,414		3,129		10,370		11,706
Natural gas (Mcf)		23,707		37,989		76,316		110,015

Average sales prices received:
Crude oil (Barrels)	$	70.13	$	67.30	$	71.54	$	49.17
Natural gas (Mcf)	$	4.98	$	3.31	$	5.20	$	4.00

The Partnership had interests in eleven productive wells during the third quarters of 2010 and 2009. The Partnership has interests in two significant wells, the Rob L RA SUA CL&F #1 (“Gumbo II”) well and the HBR A Big Gas Unit (“HBR A”) well. During the third quarter of 2009, the HBR A and Gumbo II wells accounted for 63.0% and 92.2% of the Partnership’s crude oil and natural gas sales volumes, respectively. During the third quarter of 2010, the HBR A and the Gumbo II accounted for 65.7% and 84% of the Partnership’s crude oil and natural gas sales volumes, respectively. The operator of the Gumbo II well slowly increased production volumes from the well during the first seven months of 2010, resulting in increased volumes for the three and nine month periods ended September 30, 2010. Third quarter 2010 sales volumes from the Gumbo II well were also higher than third quarter 2009 sales volumes because the well was shut-in for thirteen days during the third quarter of 2009 due to issues with the oil pipeline. The Gumbo II well did produce at full production rates during the third quarter of 2010. However, production volumes from the HBR A well have declined significantly over the past year. Production volumes from the HBR A well, net to this Partnership, were 278 Bbl and 10,563 Mcf during the third quarter of 2010 compared to 799 Bbl and 27,007 MCF during the third quarter of 2009. The eight Cole Ranch field wells, which began production in April 2007, averaged 37 barrels of crude oil production and 119 Mcf of natural gas production per day during the third quarter of 2009. The Partnership owns a 50% working interest and a 37.5% revenue interest in these wells. During the third quarter of 2010, these same eight wells averaged approximately 34 barrels of crude oil production and 112 Mcf of natural gas production per day.

Crude oil and natural gas average sales prices increased from the third quarter of 2009. Average crude oil sales prices increased by 4.2% and average natural gas sales prices increased by 50.5% over the comparative quarters. Total revenues increased by $21,247, or 6.3% in the third quarter of 2010 compared to the third quarter of 2009 as a result of these increased prices. The declining volumes from the HBR A well will lead to continuing declines in sales volumes in future quarters. The current estimated reserve life of the HBR A well is estimated to be approximately 14 months using current prices and costs. In addition, gas prices have decreased and it is expected that average gas prices received during the fourth quarter will decline from third quarter levels.

In January 2009, the SEC adopted a new rule related to modernizing reserve calculation and disclosure requirements for oil and gas companies, which became effective prospectively for annual reporting periods ending on or after December 31, 2009. In addition to expanding the definition and disclosure requirements for crude oil and natural gas reserves, the new rule changes the requirements for determining quantities of crude oil and natural gas reserves. The new rule requires disclosure of crude oil and natural gas proved reserves by significant geographic area, using the un-weighted arithmetic average of first-day-of-the-month commodity prices over the preceding 12-month period, rather than end-of-period prices, and allows the use of reliable technologies to estimate proved crude oil and natural gas reserves, if those technologies have been demonstrated to result in reliable conclusions about reserves volumes. Reserve and related information for September 30, 2010 is presented consistent with the requirements of the new rule. The new rule does not allow prior-year reserve information to be restated, so all information related to September 30, 2009 is presented consistent with prior SEC rules for the estimation of proved reserves. The effect of applying the new definition of reliable technology and other non-price related aspects of the updated rules did not significantly impact 2010 net proved reserve volumes. All of the Partnership’s reserves are located in the United States.

The estimated net proved crude oil and natural gas reserves as of September 30, 2010 and 2009 are summarized below. The quantities of proved crude oil and natural gas reserves discussed in this section include only the amounts which the Partnership reasonably expects to recover in the future from known oil and gas reservoirs under the current economic and operating conditions. Proved reserves include only quantities that the Partnership expects to recover commercially using current prices, costs, existing regulatory practices, and technology. Therefore, any changes in future prices, costs, regulations, technology or other unforeseen factors could materially increase or decrease the proved reserve estimates.

Net proved reserves	Oil (Bbl)	Gas (Mcf)
September 30, 2010	38,607	146,678
September 30, 2009	30,424	278,722

Three months ended September 30, 2010 compared to the three months ended September 30, 2009

The Partnership had net income of $37,579 for the three month period ended September 30, 2010, compared to net income of $55,591 for the three month period ended September 30, 2009.

While overall sales volumes decreased during the three months ended September 30, 2010, sales prices received for the Partnership’s production increased. The average oil price received on a comparative basis increased from $67.30 per barrel of crude oil during the three months ended September 30, 2009 to $70.13 per barrel during the three months ended September 30, 2010, an increase of 4.2%. Natural gas prices also increased from an average price of $3.31 per Mcf of natural gas produced during the quarter ended September 30, 2009 to $4.98 per Mcf for the quarter ended September 30, 2010, an increase of 50.5%. As a result of the sales price increases, oil and gas sales revenues increased by $21,247, or 6.3% for the three months ended September 30, 2010.

Lease operating costs increased from $67,811 during the quarter ended September 30, 2009 to $99,776 during the quarter ended September 30, 2010, primarily due to a true up of lease operating expense accruals associated with the Cole Ranch wells.

Depletion expense rose from $125,549 incurred during the three month period ended September 30, 2009 to $145,983 incurred for the three month period ended September 30, 2010, primarily due to the rise in the overall depletion rate resulting from the overall drop in reserve estimates related to the Partnership’s interest in the HBR A well.

General and administrative costs decreased from $69,000 incurred during the three months ended September 30, 2009 to $45,067 incurred during the three months ended September 30, 2010. RELP has gradually been reducing its total overhead costs and total overhead charged to partnerships has decreased in 2010 from 2009 levels. The administrative overhead charge to the Partnership decreased from $48,782 for the three months ended September 2009 to $32,657 for the three months ended September 30, 2010.

Nine months ended September 30, 2010 compared to the nine months ended September 30, 2009

The Partnership had net income of $240,488 for the nine month period ended September 30, 2010, compared to a net loss of $589,560 for the nine month period ended September 30, 2009. The primary cause of this increase in net income is lower property impairment expenses, as discussed below.

While overall sales volumes decreased during the nine months ended September 30, 2010, sales prices received for the Partnership’s production increased. The average oil price received on a comparative basis increased from $49.17 per barrel of crude oil during the first nine months of 2009 to $71.54 per barrel during the first nine months of 2010, an increase of 45.5%. Natural gas prices also increased from an average price of $4.00 per Mcf of natural gas produced during the nine months ended September 30, 2009 to $5.20 per Mcf for the nine months ended September 30, 2010, an increase of 30%. Because of these large increases in average prices for crude oil and natural gas sales, the Partnership’s oil and gas sales revenues rose by $123,417, or 12.2% for the nine months ended September 30, 2010.

Lease operating costs decreased from $236,272 during the nine months ended September 30, 2009 to $212,501 during the nine months ended September 30, 2010, primarily as a result of reduced ad valorem tax expenses. Production taxes decreased during the nine month period ended September 30, 2010 compared to the nine month period ended September 30, 2009 by approximately $42,000, from $61,772 to $19,473. This was the result of an approximate $45,000 adjustment received from the operator of the Gumbo II well during the second quarter of 2010. The operator refunded prior production tax payments because the well obtained a severance tax exemption from the state of Louisiana for the period from inception through February 2010.

The Partnership incurred no property impairment expense during the nine month period ended September 30, 2010. However, the decline in oil and gas prices during that occurred during the first quarter of 2009 resulted in impairment expense of proved properties totaling $566,482 for the nine month period ending September 30, 2009. Depletion expense decreased from $494,991 for the first nine months of 2009 to $442,284 for the first nine months of 2010. While overall depletion rates have increased during 2010 because of the drop in reserves associated with the Partnership’s interest in the HBR A well, the Partnership has a lower overall property basis in 2010 as a result of the 2009 property impairment totaling $566,482.

General and administrative costs decreased from $232,125 incurred during the nine months ended September 30, 2009 to $211,798 incurred during the nine months ended September 30, 2010. RELP has gradually been reducing its total overhead costs and total overhead charged to partnerships has decreased in 2010 from 2009 levels. The administrative overhead charge to the Partnership decreased from $138,310 for the nine months ended September 2009 to $129,029 for the nine months ended September 30, 2010. This decrease was partially offset by increased professional fees.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership is a “smaller reporting company” as defined by Rule 12b-2 promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and as such, is not required to provide the information required under this Item.

Item 4T. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As the managing general partner of the Partnership, Reef maintains a system of controls and procedures designed to provide reasonable assurance as to the reliability of the financial statements and other disclosures included in this report, as well as to safeguard assets from unauthorized use or disposition. The Partnership, under the supervision and with participation of its management, including the principal executive officer and principal financial officer, evaluated the effectiveness of the design and operation of its “disclosure controls and procedures” as such term is defined in Rule 13a-15(e) promulgated under the Exchange Act, as of the end of the period covered by this Quarterly Report. Based on that evaluation, the principal executive officer and principal financial officer have concluded that the Partnership’s disclosure controls and procedures are effective to ensure that information required to be disclosed by the Partnership in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and includes controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding financial disclosure.

Changes in Internal Controls

There have not been any changes in the Partnership’s internal controls over financial reporting during the fiscal quarter ended September 30, 2010 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

On August 26, 2010, Frank Stevenson ("Stevenson") filed a lawsuit, styled Stevenson v. Wayne Kirk, Michael J. Mauceli, Reef Global Energy Ventures II, et al., (Cause No. 10-10647) in the 191st Judicial District Court, Dallas County, Texas. Stevenson also named as defendants Reef Global Energy VII and multiple other Reef Joint Ventures as well as Reef Securities, Inc. On September 22, 2010, James and Carol Estle (the “Estles”) and Nancy Dykes Thurmond Antolic (“Antolic”) joined the suit as additional plaintiffs. Stevenson, the Estles, and Antolic were participants in many of the named Reef defendant programs/Joint Ventures. Stevenson invested in Reef Global Energy VII, L.P. but the Estles and Antolic did not. Collectively, Stevenson, the Estles, and Antolic are seeking in excess of $1 million in compensatory damages as well as exemplary damages, attorneys’ fees, pre- and post-judgment interest, and costs and they assert vague claims, with virtually no factual allegations in support, for fraud, rescission under the Texas Securities Act, control person liability under the Texas Securities Act, and breach of fiduciary duty.. Notwithstanding the fact that the Petition is wholly deficient and fails to allege a factual basis for any of the claims asserted, Defendants believe Stevenson's, the Estles’, and Antolic’s claims are meritless, and with respect to many of the Reef programs referred to in the Petition, Defendants believe that the claims for fraud, particularly if based upon any purported guarantees or projections, are barred by limitations, as are any claims for rescission or breach of fiduciary duty with respect to those programs. In addition, with respect to all programs in which Stevenson, the Estles, and Antolic invested, they received thorough disclosure documents that disclosed all material facts and risks with respect to participation in such programs, particularly the fact that no guarantees or promises could be made or relied upon. Defendants (including Reef Global Energy VII, L.P.) intend to vigorously defend this lawsuit and to seek damages against Stevenson, the Estles, and Antolic based upon, among other things, breaches of representations and warranties made by them as well as the indemnification provisions of the documents executed by each of them.

Item 1A. Risk Factors

There were no material changes in the Risk Factors applicable to the Partnership as set forth in the Annual Report.

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

None.

Item 3. Default Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

Item 6. Exhibits

Exhibits

31.1

Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

Pursuant to the requirements 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.

	REEF GLOBAL ENERGY VII, L.P.

	By:	Reef Oil & Gas Partners, L.P.
		Managing General Partner

	By:	Reef Oil & Gas Partners, GP, LLC,
		its general partner

Dated: November 15, 2010	By:	/s/ Michael J. Mauceli
		Michael J. Mauceli
		Manager and Member
		(Principal Executive Officer)

Dated: November 15, 2010	By:	/s/ Daniel C. Sibley
		Daniel C. Sibley
		Chief Financial Officer and General Counsel of
		Reef Exploration, L.P.
		(Principal Financial and Accounting Officer)

EXHIBIT INDEX

Exhibits

31.1

Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2

Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1

Certification of the Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2

Certification of the Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Attached files

Reef Global Energy VII, L.P. Reports

Also read