RVEP Rio Vista Energy Partners L.P. (MM)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2008

OR

o		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: 000-50394

Rio Vista Energy Partners L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware		20-0153267
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
1313 E. Alton Gloor Blvd., Suite J, Brownsville, Texas		78526
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (956) 831-0886

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: Common Units

Indicate by check mark if the registrant is a well-known seasonal issuer as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

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 þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K or any amendment to this Form 10-K. þ

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

Large Accelerated Filer o		Accelerated Filer o		Non-Accelerated Filer o		Smaller Reporting Company þ

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

The aggregate market value of the voting units held by non-affiliates of the Registrant was $19,337,586 as of June 30, 2008.

The number of Common Units outstanding on March 30, 2009 was 2,762,463.

DOCUMENTS INCORPORATED BY REFERENCE

None.

 

 

TABLE OF CONTENTS

ITEM		PAGE NO.
Part I
1 and 2. Business and Properties			1
1A. Risk Factors			20
1B. Unresolved Staff Comments			40
3. Legal Proceedings			41
4. Submission of Matters to a Vote of Security Holders			42
Part II
5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities			43
6. Selected Financial Data			46
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			46
7A. Quantitative and Qualitative Disclosures About Market Risks			66
8. Financial Statements and Supplementary Data			67
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			120
9A(T). Controls and Procedures			120
9B. Other Information			121
Part III
10. Directors, Executive Officers and Corporate Governance			122
11. Executive Compensation			125
12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters			129
13. Certain Relationships and Related Transactions, and Director Independence			133
14. Principal Accountant Fees and Services			136
Part IV
15. Exhibits and Financial Statement Schedules			137
Exhibit 10.60
Exhibit 10.61
Exhibit 10.62
Exhibit 10.63
Exhibit 10.64
Exhibit 10.65
Exhibit 10.66
Exhibit 10.67
Exhibit 10.68
Exhibit 21
Exhibit 23.1
Exhibit 23.2
Exhibit 31.1
Exhibit 31.2
Exhibit 32

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The statements contained in this Annual Report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. This Annual Report contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:

	•		the volatility of realized natural gas prices;
	•		the discovery, estimation, development and replacement of oil and natural gas reserves;
	•		our business and financial strategy;
	•		our drilling locations;
	•		technology;
	•		our cash flow, liquidity and financial position;
	•		our production volumes;
	•		our lease operating expenses, general and administrative costs and finding and development costs;
	•		the availability of drilling and production equipment, labor and other services;
	•		our future operating results;
	•		our prospect development and property acquisitions;
	•		the marketing of oil and natural gas;
	•		competition in the oil and natural gas industry and the transportation and terminaling business;
	•		the impact of weather and the occurrence of natural disasters such as fires, floods, hurricanes, earthquakes and other catastrophic events and natural disasters;
	•		governmental regulation of the oil and natural gas industry and the transportation and terminaling business;
	•		required capital expenditures;
	•		cash distributions and qualified income;
	•		developments in oil producing and natural gas producing countries; and
	•		our strategic plans, objectives, expectations and intentions for future operations;
	•		our ability to restructure the TCW Credit Facility and/or the RZB Note under terms satisfactory to us.

All of these types of statements, other than statements of historical fact included in this Annual Report are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this Annual Report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk Factors” section and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section and elsewhere in this Annual Report. All forward-looking statements speak only as of the date of this Annual Report. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise.

GLOSSARY OF TERMS

As commonly used in the oil and gas industry and as used in this Annual Report on Form 10-K, the following terms have the following meanings:

Bbl. One stock tank barrel or 42 United States gallons liquid volume.

Bcf. One billion cubic feet.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

Btu. One British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

FERC. Federal Energy Regulatory Commission.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Hp. Horsepower

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million Btus.

MMcf. One million cubic feet.

MMcf/d. One MMcf per day.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of gas to one Bbl of oil, condensate or natural gas liquids.

MMcfe/d. One MMcfe per day.

MMMBtu. One billion Btus.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil, condensate and natural gas liquids.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved reserves. Proved oil and gas reserves are the estimated quantities of gas, natural gas liquids and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. The definition of proved reserves is in accordance with the Securities and Exchange Commission’s definition set forth in Regulation S-X Rule 4-10(a) and its subsequent staff interpretations and guidance.

Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.

Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of economically productive oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized Measure. Standardized Measure, or standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities, is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses, such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Our Standardized Measure does not include future income tax expenses because our reserves are owned by our subsidiary Rio Vista Penny LLC, which is not subject to income taxes.

Successful well. A well capable of producing oil and/or gas in commercial quantities.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Unproved reserves. Lease acreage on which wells have not been drilled and where it is either probable or possible that the acreage contains reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production

PART I

Items 1 and 2. Business and Properties.

Rio Vista Energy Partners L.P. and its consolidated subsidiaries (not including the General Partner) are hereinafter referred to as “Rio Vista”. When referring to Rio Vista and using phrases such as “we,” “our,” “us,” or the “Company,” our intent is to refer to Rio Vista and its consolidated subsidiaries as a whole or on an entity basis, depending on the context in which the statements are made.

General

Rio Vista Energy Partners L.P. (Rio Vista), a Delaware limited partnership, was formed by Penn Octane Corporation (Penn Octane) on July 10, 2003 and was a wholly owned subsidiary of Penn Octane until September 30, 2004, the date that Penn Octane completed a series of transactions that (i) transferred substantially all of its owned pipeline and terminal assets in Brownsville, Texas and Matamoros, Mexico and certain immaterial liabilities to Rio Vista Operating Partnership L.P. (RVOP), (ii) transferred Penn Octane’s 99.9% interest in RVOP to Rio Vista and (iii) distributed all of its limited partnership interests (Common Units) in Rio Vista to its common stockholders (Spin-Off), resulting in Rio Vista becoming a separate public company. The Common Units represented 98% of Rio Vista’s outstanding capital and 100% of Rio Vista’s limited partnership interests. The remaining 2% represented the General Partner interest. The General Partner interest is solely owned and controlled by Rio Vista GP LLC (General Partner). Our General Partner is 75% owned by Penn Octane and Penn Octane has 100% voting control over the General Partner pursuant to a voting agreement with the other owner of the General Partner. Our General Partner is responsible for the management of Rio Vista. Common unitholders do not participate in the management of Rio Vista.

Our principal executive offices are located at 1313 Alton Gloor, Suite J, Brownsville, Texas 78526, and our telephone number is (956) 831-0886. Our website is located at http://www.riovistaenergy.com.

Historical Assets and Operations

In August 2006, Rio Vista completed the disposition of substantially all of its U.S. LPG assets to TransMontaigne, including the Brownsville, Texas terminal facility and refined products tank farm, together with associated improvements, leases, easements, licenses and permits; an LPG sales agreement; and all of LPG inventory. In December 2007, Rio Vista completed the disposition of its remaining LPG assets to TransMontaigne, including the U.S. portion of the two pipelines from a Brownsville, Texas terminal owned by TransMontaigne to the U.S. border, along with all associated rights-of-way and easements; all of the outstanding equity interests in entities owning interests in the portion of the two pipelines that extend from the U.S. border to Matamoros, Mexico; and all of the rights for indirect control of an entity that owns a terminal site in Matamoros, Mexico. As a result, effective January 1, 2008, Rio Vista no longer operates the assets associated with the LPG business it had historically conducted.

Current Assets and Operations

In July 2007, Rio Vista acquired Regional Enterprises, Inc. (Regional), and in November 2007, Rio Vista acquired certain oil and natural gas producing properties and related assets in the State of Oklahoma formerly owned by GM Oil Properties, Inc., Penny Petroleum Corporation and GO LLC. The businesses and assets we acquired in 2007 are described further below under the subheadings “Regional Enterprises” and “Oklahoma assets.” As a result of these acquisitions in 2007, Rio Vista is now focused on the acquisition, development and production of oil and natural gas properties and related midstream assets, and the operation and development of Regional’s business consisting of transportation and terminaling. However, as discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt Obligations — TCW Credit Facility,” we may dispose of some of our assets, including our oil and gas properties in Oklahoma, in connection with the restructuring of our debt. Beginning March 1, 2008 Rio Vista operating LLC (Operating) became the operator of the Oklahoma Assets.

Regional Enterprises

In July 2007, Rio Vista acquired the business of Regional Enterprises, Inc., a Virginia corporation. The principal business of Regional is storage, transportation and railcar transloading of bulk liquids, including chemical and petroleum products owned by its customers.

Regional’s principal facilities are located on the James River in Hopewell, Virginia, where it receives bulk chemicals and petroleum products from ships and barges into approximately 10,400,000 gallons of available storage. Regional also receives product from a rail spur which is capable of receiving 15 rail cars at any one time for transloading of chemical and petroleum liquids for delivery throughout the mid-Atlantic region.

Regional utilizes its fleet of 32 tractors and 48 tankers to distribute the various products it receives as well as to perform direct hauling operations on behalf of its customers.

For the year ended December 31, 2008, Regional’s revenues were divided among transportation, storage and transloading as follows:

Year Ended December 31, 2008
		Revenue				%
Transportation		$	6,687,000				78	%
Storage			1,543,000				18	%
Transloading		343,000				4		%
Total		$	8,573,000				100	%

Transportation . Regional transports a broad range of hazardous and non-hazardous liquid products, including the following: aluminum sulfate solution, sulfuric acid, sodium hydroxide, hydrogen peroxide, ferric chloride, ferric sulfate, hypochlorite solution, hydrochloric acid, ferrous chloride and aqua ammonia. Regional’s transportation services are primarily for the most part short-haul in nature, with an estimated 85% of Regional’s deliveries being made within 150 miles of its Hopewell, Virginia terminal. Virtually all of Regional’s transportation services are provided within the states of Virginia, North Carolina, South Carolina, Georgia, Tennessee, Maryland, Pennsylvania and Delaware.

Regional currently has a fleet of approximately 48 tanker units and 32 tractors dedicated to its transportation services. The majority of tankers are constructed of stainless steel, with 11 being rubber or chlorobutyl lined, which enables them to carry the toughest corrosives. The tanker fleet also includes four aluminum-constructed tanks, which are equipped with vapor recovery. Rio Vista believes that this extensive inventory of tankers enables Regional to service the majority of its customers’ needs. The tractor fleet consists of late model, Western Star and Mack units.

Storage . Regional’s Hopewell facility has a total of 15 tanks, six of which have capacities in excess of one million gallons; of these 15 tanks, 13 tanks are for customer utilization. These tanks have a combined storage capacity of approximately 10.4 million gallons. As of December 31, 2008, Regional had two vacant tanks with a combined storage capacity of 76,000 gallons.

Regional’s loading dock is parallel to the main shipping channel with berthing dolphin clusters approximately 210 feet in length. Two six-inch and one ten-inch steel pipelines service the various tanks. All of the tanks are constructed of carbon steel, both insulated and bare skin and some with internal walls lined and unlined. Several tanks and all of the associated piping are equipped with heat via either heat transfer (hot oil) or steam. As of December 31, 2008, Regional stored the following products: two grades of asphalt, asphalt additive, sodium hydroxide, #2 oil and #4 oil.

Regional receives the products it stores by ship, barge, rail and truck. The products Regional stores are owned by its customers. Certain customers for whom Regional provides storage services also use Regional’s transportation services.

There is approximately 2.25 acres of undeveloped acreage at Regional’s Hopewell facility, which could be used to accommodate additional construction of up to an additional 4.2 million gallons of storage capacity.

Transloading . Regional provides transloading services utilizing its rail siding and off-loading facilities to transfer products from railcars to tanker trucks. Open rail access to the Norfolk Southern and CSX rail lines offers competitive rail economics and flexibility for Regional’s customers. Customers who utilize Regional’s transloading services typically do so because either their own rail service is at full capacity or Regional’s strategic location provides them with an important distribution point not available in their own distribution system. Transloading products, either from storage tanks or tankers, in railcar quantities provides a logistical pricing advantage over long-haul transportation in tanker trucks. Steam heat and compressed air is available at each railcar spot.

Regional has two transloading facilities. Regional leases siding tracks and 15 railcar slots at its Hopewell, Virginia facility, with Norfolk Southern conducting switching operations. As of December 31, 2008, Regional had no vacant slots but anticipates acquiring an additional 900 feet of track, which would result in 16 additional rail slots. Regional also has a transloading facility in Johnson City, Tennessee, where it leases siding tracks and six railcar slots. Switching operations for the Johnson City, Tennessee facility are provided by East Tennessee Railway, which services tracks over which both the CSX and Norfolk Southern railroads operate.

Headquarters Facility . Regional has approximately 2,000 square feet of office facilities at its Hopewell, Virginia headquarters from which it provides most of its management, administrative and marketing operations.

Customers . For the fiscal year ended December 31, 2008, Suffolk Sales, General Chemical Corporation and Kemira Chemicals Canada Inc. accounted for approximately 14% 10% and 12% of Regional’s revenues, respectively, and approximately 19%, 8% and 10% of Regional accounts receivables, respectively with no other individual customer accounting for more than 10% of Regional’s revenues and accounts receivable.

Competition . The terminaling and transportation industry is highly competitive. We encounter strong competition from other independent operators and from companies in acquiring equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to bid for contracts at rates which are more attractive to customers than our financial or human resources permit.

We are also affected by competition for availability of specialized equipment. Certain trucking equipment, including tankers, require significant lead time and possible higher prices to obtain. Accordingly, we may not be able to bid for additional business which require equipment not currently available to us.

Employees . As of December 31, 2008, Regional had a total of approximately 61 full- and part-time employees, consisting of 28 drivers, 17 terminal operators, two mechanics and 14 office staff.

Environmental and Regulatory . Regional is a licensed contract or common carrier and holds permits with the Hopewell wastewater treatment facility for treatment and disposal of its wastewater generated through rainwater runoff and tanker washing operations. Regional is subject to various laws and regulations, including those relating to labor, maritime, transportation, environment and motor carrier.

Tax Structure . Regional’s assets and operations are conducted within a C-Corp for federal income tax purposes, as many of its activities are not considered “Qualified Income”. Rio Vista intends to explore options regarding the reorganization of some or all of its Regional assets that produce qualifying income into a more efficient tax structure.

Other . Regional qualifies as a small business contractor and vendor capable of storing, transporting and supplying bulk chemical and petroleum products on behalf of U.S. government agencies. Regional intends to seek contracts with the Department of Defense and the Defense Energy Support Center based on the proximity of its Hopewell facilities to multiple U.S. military bases.

Oklahoma Assets

In November 2007, Rio Vista Penny LLC (Rio Vista Penny), an indirect, wholly-owned subsidiary of Rio Vista, completed the purchase of assets from G M Oil Properties, Inc., an Oklahoma corporation (GM Oil) and Penny Petroleum Corporation, an Oklahoma corporation (Penny Petroleum) pursuant to which we acquired real and personal property interests in certain oil and gas properties located in Haskell, McIntosh and Pittsburg counties in Oklahoma, including all of the outstanding capital stock of MV Pipeline Company (MV), an Oklahoma corporation.

In addition, in November 2007, Rio Vista GO, LLC (Rio Vista GO) an indirect, wholly-owned subsidiary of Rio Vista, acquired all of the membership interests of GO, LLC, an Oklahoma limited liability company (GO). GO operates an oil and gas pipeline business located in Haskell and Pittsburg counties in Oklahoma.

Exploration and Production Assets . The Oklahoma Assets include approximately 15,100 net acres located in McIntosh, Haskell and Pittsburg counties in Oklahoma. The Oklahoma Assets also include a 25% participation interest on 4,800 acres owned by Concorde Resources. These assets represent a majority interest in 114 wells that we now operate and 24 non-operated wells in the Booch Sand, Hartshorne Cold Bed Methane, Georgia’s Fork and Spiro formations.

Gathering . The Oklahoma Assets also include the wholly-owned and operated 25-mile Brooken pipeline that gathers natural gas from several properties located in Haskell and Pittsburg counties, as well as MV’s wholly-owned and operated 40-mile pipeline that receives natural gas from leases in the Texanna area north of Lake Eufaula and delivers product to the ONEOK intrastate pipeline in McIntosh County, Oklahoma. The pipeline consists of 40 miles of Class I pipelines, a low-pressure gas gathering system and a 3,000 horsepower central compressor station with a capacity of 50 MMcf per day.

Proved Reserves. Our proved reserves at December 31, 2008 were 22.5 Bcf, all of which were gas. Approximately 8.1 Bcf were classified as proved developed, with a total Standardized Measure value of $9.0 million. At December 31, 2008, we operated 114 wells, or 83%, of our 138 productive wells. Our average proved reserves-to-production ratio, or average reserve life, is approximately 82.5 years, based on our December 31, 2008 reserve report and annualized production of current production levels.

Core Operating Areas

The long-lived proved producing properties are principally comprised of majority interests in 177 operated wells (63 undeveloped as of December 31, 2008) and 24 non-operated wells located on either side of Lake Eufaula in the “Crouch Area”, the “Texanna Area”, the “Brooken Area” and the “Canadian Area” with production derived primarily from the Booch sand and Hartshorne Coal Bed Methane reservoirs. We also derive a smaller portion of our reserves from the George’s Fork and Spiro reservoirs. Rio Vista estimates that it has an average revenue interest of approximately 56.0% in these leased interests. Characteristics of our reservoirs are as follows:

Booch sand:

	•		Acreage surrounding Lake Eufaula has net sand thickness of 25 feet
	•		Land surrounding the edges and underneath Lake Eufaula has locations with net sand thickness up to 200 feet
	•		Well potential: 732 MMcf – 827 MMcf per well

Hartshorne coal bed methane:

	•		Coal thickness contours ranging from a minimum of 2 feet to over 4 feet in select areas
	•		Well potential: 514 MMcf – 827 MMcf per well

The following diagram illustrates the location of the principal fields and pipeline facilities associated with the Oklahoma assets.

T exanna . The Texanna Area, which is located on the north side of Lake Eufaula, is the area where there has been a significant amount of Booch operating history. Historically, over 200 Bcf has been produced from this formation in this area. Our current proved reserves in this region are based on a second Booch formation which overlays the original Booch formation. In addition there is current production from Hartshorne formations.

Crouch. The Crouch Area, which is located on the north side of Lake Eufaula, immediately north of the Texanna Area currently produces from the Booch, Georges Fork, Spiro, Hartshorne and Cromwell formations.

The Texanna and Crouch Areas are located within our MV Pipeline gathering system. The MV pipeline gathers natural gas from leases in the Texanna and Crouch Areas north of Lake Eufaula and delivers to the ONEOK Gas Transportation, LLC (Oneok) intrastate pipeline in McIntosh County. The MV Pipeline is 40 miles in length, Class I, low-pressure gas gathering system and is joined to a 3,000 hp central compressor station with capacity of 50 MMcf/d. This gathering system was originally constructed in 1984, upgraded in 1998 and 2 new compressors were added during 2006.

All of our production associated with the MV Pipeline and Brooken Pipeline (see below) is sold to Clearwater Enterprises LLC (Clearwater). The price we receive (excluding the impact of hedges) is based on the Oneok monthly index price (MV Pipeline production) or the Centerpoint Energy Gas Transmission (CEGT) index less fuel, gathering and compression. The Oneok and CEGT indexes historically trade at an approximate 10% — 30% discount to the NYMEX monthly averages.

Brooken. The Brooken Area is located on the south side of Lake Eufaula at the intersection of Haskell, McIntosh and Pittsburg counties. Our proven reserves in this are primarily relate to the Booch sand, and Hartshorne Coal Bed Methane formations. All of the production in this area is gathered by our Brooken pipeline gathering system. The Brooken pipeline is 25 miles long and has a capacity of 10 MMcf/d. The Brooken Pipeline was originally constructed in 1992. All of the production on the Brooken Pipeline connects to the Centerpoint Energy Field Services gathering system and is sold by Clearwater based on the monthly CEGT index less fuel, gathering, and compression.

We also perform limited gas gathering activities for third-parties which utilize our Brooken pipeline system. The fee charged to third-party producers is set by contract and ranges from $0.70 to $0.75 per Mcf plus line loss and any compressor fuel. We aggregate these volumes with our production and sell all the gas through our meters to the same purchasers. These revenues are collected and distributed to the third-party producers in the normal course of our revenue distribution cycle. We do not take any commodity risk associated with third party gas as we buy and sell this production on similarly posted indexes which provide a guaranteed fixed margin. Most of our gas gathering lines are not subject to United States Department of Transportation (US DOT) safety regulations.

Canadian. The Canadian Area is located southwest of the Brooken Area. It is an area characterized by horizontal drilling for the Hartshorne coal beds. These wells typically produce at significantly higher rates and higher ultimate reserve recovery than the wells in the vertical drilling areas. The cost for the horizontal wells is about three times greater than drilling a vertical well for the same Hartshorne target. Most of the wells currently producing in this area are operated by third parties. All of the wells operated and non-operated feed into third party gathering systems. All of the production from this area is sold under sales agreements which provide for prices that are tied to the CEGT monthly and/or beginning of month indexes, less fuel, gathering, compression and marketing fees.

Drilling Activity

During the year ended December 31, 2008, we drilled the following wells:

						Net
		Working				Revenue
Well Name		Interest				Interest				Type of well		Net Cost
Urquhart 2			100.0	%			82.8	%		Vert. — Coal		$	152,887
Brinsfield #3			92.8	%			75.4	%		Vert. — U. Booch		$	75,790
Haskett #2			99.5	%			81.5	%		Vert. — Coal		$	175,404
Groseclos #3V-17			100.0	%			85.2	%		Vert. — U. Booch		$	198,191
Davis B #2			99.9	%			85.1	%		Vert. — Coal		$	151,725
Tom 1A-1			100.0	%			81.4	%		Vert. — Coal		$	131,666
Donna 1			100.0	%			80.1	%		Vert. — Coal		$	166,849
Cannon 1-31			100.0	%			76.8	%		Vert. — Spiro		$	740,501
Belt 2V-24			100.0	%			81.3	%		Vert. — Savannah		$	76,577
Ace #2-36			51.0	%			41.4	%		Horiz. — Coal		$	672,412

The above wells produced a combined 12,595 Mcf (net) during the month of December 2008.

We are currently not drilling any additional wells based on the current economics associated with natural gas in the area of our leased properties and due to our inability to obtain additional sources of funding for drilling.

If drilling activity were to resume, we intend to concentrate our drilling activity on lower risk, development properties. The number, types, and location of wells we drill will vary depending on our capital budget, the cost of each well, anticipated production and the estimated recoverable reserves attributable to each well. We currently require additional funding to allow us to complete the remainder of our development program.

We currently estimate that the cost to drill a new vertical well (gross) will be approximately $172,000, and the cost to drill a new horizontal well will be approximately $780,000.

The information contained in this report about past operations of our wells should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. Productive wells are those that produce commercial quantities of oil and gas, regardless of whether they generate a reasonable rate of return. The ability for us to develop a portion or all of the above wells is contingent on our having adequate capital on hand.

As shown in the tables below, as of December 31, 2008, we had 63 proved undeveloped drilling locations (specific drilling locations as to which our independent engineering firm, Lee Keeling and Associates, Inc., assigned proved undeveloped reserves as of such date).

GAS RESERVES BY FIELD

		OPERATED
						GAS RESERVES-MCF
		WELLS				GROSS				NET
FIELD
BROOKEN			22				6,569.530				2,935.658
CANADIAN			6				4,330.734				1,272.063
TEXANNA			35				13,499.604				10,204.398
TOTAL PROVED UNDEVELOPED			63				24,399.868				14,412.119

GAS RESERVES BY RESERVOIR

		OPERATED
						GAS RESERVES-MCF
		WELLS				GROSS				NET
RESERVOIR
BOOCH			8				6,150.338				4,623.062
HARTSHORNE COAL			55				18,249.530				9,789.057
TOTAL PROVED UNDEVELOPED			63				24,399.868				14,412.119

Oil and Natural Gas Prices

Our natural gas production is sold to purchasers based on the local monthly index price, which typically is approximately 70% — 90% of the NYMEX monthly average gas prices less any direct costs for transportation, fuel and shrinkage. We recoup certain of the transportation costs that we pay related to our own gathering systems.

We may enter into forward sales contracts to reduce the impact of commodity price volatility on our cash flow from operations. By removing the price volatility from a significant portion of our oil and gas production, we mitigate, but not eliminate, the potential effects of fluctuating oil and gas prices on our cash flow from operations for those periods. We must obtain approval from TCW before we actual enter into any future sales contracts.

Oil and Gas Data

Proved Reserves

Proved oil and gas reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements, but not escalations based on future conditions. For additional information regarding estimates of oil and gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future cash flows and the changes in discounted future cash flows, see Supplementary Oil and Gas Data (Unaudited) in Item 8. “Financial Statements and Supplementary Data.”

The following table presents our estimated net proved oil and gas reserves and the present value of our estimated proved reserves at December 31, 2007 and 2008, based on the reserve reports prepared by Lee Keeling and Associates, Inc. The Standardized Measure values shown in the table are not intended to represent the market value of our estimated oil and gas reserves at such dates.

		December 31,
		2007				2008
Reserve Data:
Estimated net proved reserves:
Gas (Bcf)			35.589				22.494
Oil (MMbls)			0.0				0.0
Total (Bcfe)			35.589				22.494
Proved developed (Bcfe)			12.766				8.082
Proved undeveloped (Bcfe)			22.823				14.412
Proved developed reserves as a % of total proved reserves			35.87	%			35.93	%
Standardized Measure (in millions) (1)		$	41.272			$	13.305
Representative Gas Price per MCF (2) :		$	5.03			$	3.60

The data in the above tables are estimates. Oil and gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and gas that are ultimately recovered.

Breakdown of Gas Sales — December 2008

		Price
		Realized (a)				Gas Production
		(MCF)				(MCF)
Total Operated Wells		$	3.69				40,488
Total Non-operated Wells		$	2.25				2,688
Weighted Average Price Realized		$	3.60				43,176
Relevant Indexes (b)
NYMEX December 2008		$	6.89
Oneok December 2008 Index		$	4.80
CEGT Index — Daily Average December 2008		$	4.64
CEGT Index — December 2008		$	4.21

These reserve estimates are reviewed internally by management, with final approval by our Chairman of the Board. The process performed by Lee Keeling and Associates, Inc. to estimate the December 31, 2008 reserve amounts included their preparation of our estimated reserve quantities, future producing rates, future net revenue and the present value of such future net revenue. The independent engineering firm also prepared our estimates with respect to reserve categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10 (a) and subsequent Securities and Exchange Commission (SEC) staff interpretations and guidance. In the conduct of their preparation of the reserve estimates, Lee Keeling and Associates, Inc. did not independently verify the accuracy and completeness of information and data furnished by the Company with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of their work, something came to their attention which brought into question the validity or sufficiency of any such information or data, they did not rely on such information or data until they had satisfactorily resolved their questions relating thereto. Their estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions. We have not filed reserve estimates with any Federal authority or agency.

Future prices received for production may vary, perhaps significantly, from the prices assumed for purposes of our estimate of Standardized Measure. The Standardized Measure shown should not be construed as the market value of the reserves at the date shown. The 10% discount factor used to calculate Standardized Measure, which is required by Statement of Financial Accounting Standard (SFAS) No. 69, “Disclosures about Oil and Gas Producing Activities,” is not necessarily the most appropriate discount rate. The Standardized Measure, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Production and Price History

The following table sets forth information regarding net production of oil and gas and certain price information for the period November 19, 2007 to December 31, 2007 and the year ended December 31, 2008, which are the periods during which we owned the Oklahoma Assets:

		November 19, 2007 to December 31, 2007												Year ended December 31, 2008
						Non-												Non-
		Operated				Operated								Operated				Operated
		Wells				Wells				Total				Wells				Wells				Total
Production:
Gas production (Mcf)			64,391				15,905				80,296				450,395				70,730				521,125
Oil production (MBbls)			—				—				—				—				—				—
Total production (Mcfe)			64,391				15,905				80,296				450,395				70,730				521,125
Average daily production (Mcfe/d)			1,056				260				1,316				1,234				194				1,428
Weighted Average Realized Prices (1),(2) :
Gas (Mcf)		$	5.33			$	4.23			$	5.11			$	5.99			$	5.38			$	5.91
Oil (Bbl)		$	—			$	—			$	—			$	—			$	—			$	—
Total (Mcfe)		$	5.33			$	4.23			$	5.11			$	5.99			$	5.38			$	5.91

Productive Wells

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2008. Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections to commence deliveries. “Gross” wells refers to the total number of producing wells in which we have an interest, and “net” wells refers to the sum of our fractional revenue interests owned in gross wells.

GAS RESERVES BY FIELD

		OPERATED
						NET				GAS RESERVES-MCF								NET REVENUE
		WELLS				ACRES				GROSS				NET				INTERESTS
BROOKEN			39				4,999				6,713.831				4,392.880				65.43	%
CANADIAN			16				574				3,068.581				1,119.642				36.49	%
CROUCH AREA			47				6,620				915.424				670.909				73.29	%
TEXANNA			4				0				347.268				295.630				85.13	%
OTHER			8				2,242				1,193.858				926.516				77.61	%
TOTAL PROVED DEVELOPED			114				14,435				12,238.962				7,405.577				60.51	%

		NON-OPERATED
						NET				GAS RESERVES-MCF								NET REVENUE
		WELLS				ACRES				GROSS				NET				INTERESTS
BROOKEN			12				217				523.986				101.864				19.44	%
CANADIAN			6				199				2,373.143				569.554				24.00	%
CROUCH AREA			2				0				0				0				0.00	%
TEXANNA			0				0				0				0				0.00	%
OTHER			4				160				601.020				5.134				0.85	%
TOTAL PROVED DEVELOPED			24				576				3,498.149				676.552				19.34	%

		TOTAL
						NET				GAS RESERVES-MCF								NET REVENUE
		WELLS				ACRES				GROSS				NET				INTERESTS
BROOKEN			51				5,216				7,237.817				4,494.744				62.10	%
CANADIAN			22				773				5,441.724				1,689.196				31.04	%
CROUCH AREA			49				6,620				915.424				670.909				73.29	%
TEXANNA			4				0				347.268				295.630				85.13	%
OTHER			12				2,402				1,794.878				931.650				51.91	%
TOTAL PROVED DEVELOPED			138				15,011				15,737.111				8,082.129				51.36	%

GAS RESERVES BY RESERVOIR

		OPERATED
						NET				GAS RESERVES-MCF								NET REVENUE
		WELLS				ACRES				GROSS				NET				INTERESTS
BOOCH			33				6,072				4,983.136				3,359.632				67.42	%
GEORGES FORK			33				4,939				231.275				190.753				82.48	%
HARTSHORNE COAL			27				669				4,254.925				2,187.801				51.42	%
PITTSBURG CBM AREA			4				54				945.588				492.540				52.09	%
SPIRO			8				1,721				492.177				379.794				77.17	%
OTHER			9				980				1,331.861				795.056				59.70	%
TOTAL PROVED DEVELOPED			114				14,435				12,238.962				7,405.576				60.51	%

		NON-OPERATED
						NET				GAS RESERVES-MCF								NET REVENUE
		WELLS				ACRES				GROSS				NET				INTERESTS
BOOCH			12				217				523.986				101.864				19.44	%
GEORGES FORK			0				0				0				0				0.00	%
HARTSHORNE COAL			11				199				2,974.163				574.689				19.32	%
PITTSBURG CBM AREA			1				160				0								0.00	%
SPIRO			0				0				0				0				0.00	%
OTHER			0				0				0				0				0.00	%
TOTAL PROVED DEVELOPED			24				576				3,498.149				676.553				19.34	%

		TOTAL
						NET				GAS RESERVES-MCF								NET REVENUE
		WELLS				ACRES				GROSS				NET				INTERESTS
BOOCH			45				6,289				5,507.122				3,461.496				62.85	%
GEORGES FORK			33				4,939				231.275				190.753				82.48	%
HARTSHORNE COAL			38				868				7,229.088				2,762.490				38.21	%
PITTSBURG CBM AREA			5				214				945.588				492.540				52.09	%
SPIRO			8				1,721				492.177				379.794				77.17	%
OTHER			9				980				1,331.861				795.056				59.70	%
TOTAL PROVED DEVELOPED			138				15,011				15,737.111				8,082.129				51.36	%

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2008, relating to our leasehold acreage:

		Developed								Undeveloped								Total
		Acreage								Acreage								Acreage
		Gross				Net				Gross				Net				Gross				Net
Operated			18,640				14,435				0				0				18,640				14,435
Non-operated			2,880				576				0				0				2,880				576
Total			21,520				15,011				0				0				21,520				15,011

Oil and Gas Operational Overview

We seek to be the operator of wells in which we have an interest. Effective March 1, 2008, Rio Vista Penny LLC became the operator of the wells which were previously operated, under a transition operating agreement, by the predecessor entity, GM Oil Properties Inc., from the date of acquisition of the Oklahoma assets through February 28, 2008. As operator, we design and manage the drilling and enhancement activities and supervise operation and maintenance activities on a day-to-day basis. In connection with the acquisition of the Oklahoma Assets, we obtained a completion and drilling rig (which we subsequently sold), and we enter into consulting arrangements with outside third parties to supervise certain aspects of our drilling operations. We plan to enter contracts for additional third-party drilling rigs as needed to carry out our future drilling program. In addition, we utilize drilling, production and reservoir engineers, geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and gas properties.

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations in Oklahoma, and, as a result, we perform the majority of our drilling during the summer months in these areas. These seasonal anomalies can pose challenges for meeting our well drilling objectives and increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to employee shortages, increased costs or delays in operations. The demand for gas typically decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, certain gas users utilize gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.

Employees

At December 31, 2008, Rio Vista did not employ any personnel in connection with operation of the Oklahoma Assets. Beginning March 1, 2008, Rio Vista Operating LLC became the operator of the Oklahoma assets and employs approximately six employees, consisting of eight field workers and three office staff personnel as of such date.

Principal Customers

For the year ended December 31, 2008, approximately 68% of our gas production was sold through Clearwater Enterprises LLC (Clearwater) and approximately 22% was sold to Unimark, LLC. Clearwater in turns sells our production to retail customers within proximity of our gathering system. We believe that if we were to lose Clearwater as a customer, we would be able to sell our production to other customers under similar sales terms.

Competition

The oil and gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects, than our financial or human resources permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and has caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our drilling program.

Competition is also strong for attractive oil and gas producing properties, undeveloped leases and drilling rights, and we cannot guarantee that we will be able to compete satisfactorily when attempting to make further acquisitions.

Environmental Matters and Regulation

We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities. To protect against potential environmental risk, we typically obtain Phase I environmental assessments of any properties to be acquired prior to completing each acquisition.

General. Our operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our operations are subject to the same environmental laws and regulations as other companies in the oil and gas industry. These laws and regulations may:

•

require the acquisition of various permits before drilling commences;

•

require the installation of expensive pollution control equipment;

•

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

•

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

•

require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

•

impose substantial liabilities for pollution resulting from our operations; and

•

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business and consequently affects profitability. In addition, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs. We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may impact our properties or operations. For the year ended December 31, 2008, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. We are not aware of any environmental issues or claims that will require material capital expenditures during 2009 or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that have a material impact on the oil and gas industry include the following:

National Environmental Policy Act. Oil and gas production activities on federal lands are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current development and production activities, as well as proposed development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and gas projects.

Resource Conservation and Recovery Act. The Resource Conservation and Recovery Act (RCRA), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the Environmental Protection Agency (EPA), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the development and production of oil, gas or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or recategorize some non-hazardous wastes as hazardous for future regulation.

We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes as they are presently classified to be significant, any legislative or regulatory reclassification of oil and gas development and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and gas development and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination.

Water Pollution Control Act. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe that we are in substantial compliance with the requirements of the Clean Water Act.

Clean Air Act. The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe that we are in substantial compliance with the requirements of the Clean Air Act.

Oil Pollution Act. The Federal Oil Pollution Act (OPA) requires owners and operators of facilities that could be the source of an oil spill into waters of the U.S. (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any such oil spill. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay the costs of cleaning up an oil spill and to compensate any parties damaged by an oil spill. Such financial assurances may be increased to as much as $150 million if a formal assessment indicates such an increase is warranted.

Other Laws and Regulation. The Kyoto Protocol to the United Nations Framework Convention on Climate Change (the Protocol) became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, typically referred to as greenhouse gases, that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.

Other Regulation of the Oil and Gas Industry

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, which frequently increases the regulatory burden. In addition, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we would incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate regulate one or more of the following:

•

the location of wells;

•

the method of drilling and casing wells;

•

rates of production from wells;

•

the surface use and restoration of properties upon which wells are drilled;

•

the plugging and abandoning of wells; and

•

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing of units or proportion of units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate development while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state typically imposes a production or severance tax with respect to the production and sale of oil, gas and natural gas liquids within its jurisdiction.

Oil and Gas Transportation and Pricing. The availability, terms and cost of transportation significantly affect sales of oil and gas. The interstate transportation and sale of oil and gas are subject to federal regulation, primarily by the FERC, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters. Federal and state regulations govern the price and terms for access to oil and gas pipeline transportation. The FERC’s regulations for interstate oil and gas transmission in some circumstances may also affect the intrastate transportation of oil and gas.

Although oil and gas prices are currently unregulated, Congress historically has been active in the area of oil and gas regulation. We cannot predict whether new legislation to regulate oil and gas operations might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties.

Rio Vista Employees

Rio Vista has no employees. At December 31, 2008, Rio Vista’s subsidiaries employed personnel in connection with the operation of their businesses as described above. The business of Rio Vista is managed by the General Partner. Penn Octane employs all persons, other than Rio Vista’s employees referred to herein, including executive officers, necessary for the operation of Rio Vista’s business.

Item 1A. Risk Factors

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. The following are some of the important factors that could affect our business, financial condition, results of operations and our actual results could differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely impair or offset our business results of operation, financial condition and prospects.

Risks Related to Our Business

We may not have sufficient cash flow from operations to make the quarterly distribution on our common units following establishment of cash reserves and payment of fees and expenses, including reimbursement of expenses to our General Partner.

We may not have sufficient available cash each quarter to make the quarterly distribution of $0.25 per unit or any other amount. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of any cash reserve our General Partner establishes to provide for the proper conduct of our business, meet any of our obligations arising from any of our debt instruments, or other agreements, comply with applicable law, and provide funds for distributions to our unitholders and to our General Partner for any one or more of the next four quarters.

The amount of cash we actually generate will depend upon numerous factors related to our business that may be beyond our control, including, among other things, the risks described in these Risk Factors. In addition, the actual amount of cash that we will have available for distribution will depend on other factors, including:

	•		the level of our capital expenditures;
	•		our ability to make borrowings under our revolving credit facilities, if any, to make distributions;
	•		limitations on our subsidiaries’ ability to make distributions to us under the TCW credit facility, as discussed under Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations”;
	•		sources of cash used to fund acquisitions;
	•		debt service requirements and restrictions on distributions contained in our existing and future debt agreements;
	•		interest payments;
	•		fluctuations in our working capital needs;

	•		general and administrative expenses, including expenses we will incur as a result of being a public company;
	•		cash settlement of commodity derivative contracts;
	•		timing and collectibility of receivables; and

•

the amount of cash reserves, which we expect to be substantial, established by the General Partner for the proper conduct of our business.

Our estimate of the “available cash” as defined in the partnership agreement, is necessary for us to make a distribution on all units at the target distribution rate for each of the four quarters ending December 31, 2009 and is based on assumptions that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated.

Our estimate of “available cash” as defined in the partnership agreement, is necessary for us to make a distribution on all units at the target distribution rate for each of the four quarters ending December 31, 2009 and is based on our management’s calculations, and we have not received an opinion or report on it from any independent accountant. This estimate is based on assumptions about development, production, oil and natural gas prices, settlements under commodity derivative contracts, capital expenditures, expenses, borrowings and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. If any of these assumptions prove to have been inaccurate, our actual results may differ materially from those set forth in our estimates, and we may be unable to make all or part of the initial quarterly distribution on our units.

Our oil and natural gas reserves naturally decline, and we will be unable to sustain distributions at the level of our initial quarterly distribution without making accretive acquisitions or substantial capital expenditures that maintain or grow our asset base.

Our future oil and natural gas reserves, production volumes, cash flow and ability to make distributions depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations and reduce cash available for distribution.

Because our oil and natural gas properties are a depleting asset, we will need to make substantial capital expenditures to maintain and grow our asset base, which will reduce our cash available for distribution. Because the timing and amount of these capital expenditures fluctuate each quarter, we expect to reserve substantial amounts of cash each quarter to finance these expenditures over time. We may use the reserved cash to reduce indebtedness until we make the capital expenditures. Over a longer period of time, if we do not set aside sufficient cash reserves or make sufficient expenditures to maintain our asset base, we will be unable to make distributions at the current level from cash generated from operations and would therefore expect to reduce our distributions.

If our reserves decrease and we do not reduce our distribution, then a portion of the distribution may be considered a return of part of a unitholder’s investment in us as opposed to a return on investment. Also, if we do not make sufficient growth capital expenditures, we will be unable to expand our business operations and will therefore be unable to raise the level of future distributions.

To fund our substantial capital expenditures, we will be required to use cash generated from our operations, additional borrowings or the issuance of additional equity or debt securities, or some combination thereof, which may limit our ability to make distributions at the then-current distribution rate.

The use of cash generated from operations to fund capital expenditures will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by adverse market conditions resulting from, among other things, general economic conditions and contingencies and uncertainties that are beyond our control. Our failure to obtain the funds for necessary future capital expenditures could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions.

Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to make distributions to our unitholders, either directly or indirectly. For example, our existing credit facility with TCW prohibits our Oklahoma subsidiaries from making any distributions to us unless we meet certain conditions which we do not currently expect to meet. If we are not able to receive sufficient operating cash from our subsidiaries, our ability to make distributions to our unitholders at the then-current distribution rate could be adversely affected.

In addition, incurring additional debt may significantly increase our interest expense and financial leverage. Issuing additional common units may result in significant unitholder dilution thereby increasing the aggregate amount of cash required to maintain the then-current distribution rate. Any of these events could limit our ability to make distributions at the then-current distribution rate.

We may not make cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily on our cash flow, including cash from financial reserves, working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

Oil and natural gas prices are very volatile. A decline in commodity prices will cause a decline in our cash flow from operations, which may force us to reduce our distributions or cease paying distributions altogether.

The oil and natural gas markets are very volatile, and we cannot predict future oil and natural gas prices. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

	•		our ability to make borrowings under our revolving credit facilities, if any, to make distributions;
	•		domestic and foreign supply of and demand for oil and natural gas;
	•		weather conditions;
	•		overall domestic and global economic conditions;

•

political and economic conditions in oil and natural gas producing countries, including those in the Middle East and South America;

	•		actions of the Organization of Petroleum Exporting Countries, or OPEC, and other state-controlled oil companies relating to oil price and production controls;
	•		impact of the U.S. dollar exchange rates on oil and natural gas prices;
	•		technological advances affecting energy consumption and energy supply;
	•		domestic and foreign governmental regulations and taxation;
	•		the impact of energy conservation efforts;

	•		the proximity, capacity, cost and availability of oil and natural gas pipelines and other transportation facilities;
	•		the availability of refining capacity; and

•

the price and availability of alternative fuels.

Our revenue, profitability and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, declines in commodity prices will:

	•		negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;
	•		reduce the amount of cash flow available for capital expenditures;
	•		limit our ability to borrow money or raise additional capital; and
	•		impair our ability to make distributions.

If we raise our distribution levels in response to increased cash flow during periods of relatively high commodity prices, we may not be able to sustain those distribution levels during subsequent periods of lower commodity prices.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution and adversely affect our financial condition.

The prices that we receive for our oil and natural gas production sometimes trade at a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating commodity derivative positions. The difference between the benchmark price and the price we receive is called a differential. We cannot accurately predict oil and natural gas differentials. Increases in the differential between the benchmark price for oil and natural gas and the wellhead price we receive could significantly reduce our cash available for distribution and adversely affect our financial condition.

Future price declines may result in a write-down of our asset carrying values, which could have a material adverse effect on our results of operations and limit our ability to borrow and make distributions.

Declines in oil and natural gas prices may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or development results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. If we incur impairment charges in the future, it could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our revolving credit facility, which in turn may adversely affect our ability to make cash distributions to our unitholders.

Our commodity derivative contract activities could result in financial losses or could reduce our income, which may adversely affect our ability to make distributions to our unitholders.

To achieve more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas, we may in the future enter into derivative arrangements for a significant portion of our oil and natural gas production that could result in both realized and unrealized commodity derivative losses. The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. For example, the derivative instruments we utilize are based on posted market prices, which may differ significantly from the actual crude oil, natural gas and NGL prices we realize in our operations.

Our actual future production may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the nominal amount that is subject to our derivative financial instruments, we might be forced to satisfy all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, resulting in a substantial diminution of our liquidity. As a result of these factors, our derivative activities may not be as effective as we intend in reducing the volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our derivative activities are subject to the following risks:

•

a counterparty may not perform its obligation under the applicable derivative instrument; and

•

there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, which may result in payments to our derivative counterparty that are not accompanied by our receipt of higher prices from our production in the field.

Our estimated proved reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

It is not possible to measure underground accumulations of oil or natural gas in an exact way. Oil and natural gas reserve engineering requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, future production levels and operating and development costs. In estimating our level of oil and natural gas reserves, we and our independent reserve engineers make certain assumptions that may prove to be incorrect, including assumptions relating to the level of oil and natural gas prices, future production levels, capital expenditures, operating and development costs, the effects of regulation and availability of funds. If these assumptions prove to be incorrect, our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery and our estimates of the future net cash flows from our reserves could change significantly.

Our Standardized Measure is calculated using prices and costs in effect as of the date of estimation, less future development, production and income tax expenses, and discounted to reflect the timing of future net revenue in accordance with the rules and regulations of the SEC. Over time, we may make material changes to reserve estimates to take into account changes in our assumptions and the results of actual development and production.

The reserve estimates we make for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. A lack of production history may contribute to inaccuracy in our estimates of proved reserves, future production rates and the timing of development expenditures.

The Standardized Measure of our estimated proved reserves is not necessarily the same as the current market value of our estimated proved oil and natural gas reserves. We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows in compliance with SFAS No. 69, “Disclosures about Oil and Gas Producing Activities,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Developing and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect our financial condition or results of operations and, as a result, our ability to make distributions to our unitholders.

The cost of developing, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a well. Our efforts will be uneconomical if we drill dry holes or wells that are productive but do not produce as much oil and natural gas as we had estimated. Furthermore, our development and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

	•		high costs, shortages or delivery delays of rigs, equipment, labor or other services;
	•		unexpected operational events and/or conditions;
	•		reductions in oil and natural gas prices;
	•		increases in severance taxes;
	•		limitations in the market for oil and natural gas;
	•		adverse weather conditions and natural disasters;
	•		facility or equipment malfunctions, and equipment failures or accidents;
	•		title problems;
	•		pipe or cement failures and casing collapses;
	•		compliance with environmental and other governmental requirements;
	•		environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
	•		lost or damaged oilfield development and service tools;
	•		unusual or unexpected geological formations, and pressure or irregularities in formations;
	•		loss of drilling fluid circulation;
	•		fires, blowouts, surface craterings and explosions;
	•		uncontrollable flows of oil, natural gas or well fluids; and
	•		loss of leases due to incorrect payment of royalties.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

Shortages of rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

Higher oil and natural gas prices generally increase the demand for rigs, equipment and crews and can lead to shortages of, and increasing costs for, development equipment, services and personnel. Shortages of, or increasing costs for, experienced development crews and oil field equipment and services could restrict our ability to drill the wells and conduct the operations that we currently have planned. Any delay in the development of new wells or a significant increase in development costs could reduce our revenues.

If we do not make acquisitions on economically acceptable terms, our future growth and ability to make or increase distributions will be limited.

Our ability to grow and to increase distributions to unitholders depends in part on our ability to make acquisitions that result in an increase in pro forma available cash per unit. We may be unable to make such acquisitions because we are:

	•		unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them;
	•		unable to obtain financing for these acquisitions on economically acceptable terms; or
	•		outbid by competitors.

If we are unable to acquire properties containing proved reserves, our total level of proved reserves will decline as a result of our production, and we will be limited in our ability to increase or possibly even to maintain our level of cash distributions.

Any acquisitions we complete are subject to substantial risks that could reduce our ability to make distributions to unitholders.

Even if we do make acquisitions that we believe will increase pro forma available cash per unit, these acquisitions may nevertheless result in a decrease in pro forma available cash per unit. Any acquisition involves potential risks, including, among other things:

	•		the validity of our assumptions about reserves, future production, revenues, capital expenditures, operating expenses and costs, including synergies;
	•		an inability to integrate the businesses we acquire successfully;
	•		a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;
	•		a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
	•		the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
	•		the diversion of management’s attention from other business concerns;
	•		an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
	•		natural disasters;
	•		the incurrences of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges;
	•		unforeseen difficulties encountered in operating in new geographic areas; and
	•		customer or key employee losses at the acquired businesses.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

In addition, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

Due to our lack of geographic diversification, adverse developments in our operating areas would reduce our ability to make distributions to our unitholders.

Currently, our only oil and natural gas properties and related assets are located in Oklahoma and the greatest part of Regional’s operations are conducted within a 150-mile radius of its principal facility in southeastern Virginia. Due to our lack of diversification in location, an adverse development in the relevant businesses within our geographic areas would have a significantly greater impact on our results of operations and cash available for distribution to our unitholders than if we maintained more diverse locations.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue to allow us to make distributions to our unitholders.

The oil and natural gas industry is intensely competitive with respect to acquiring prospects and productive properties, marketing oil and natural gas and securing equipment and trained personnel, and we compete with other companies that have greater resources. Many of our competitors are major and large independent oil and natural gas companies, and possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil and natural gas but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, there is substantial competition for investment capital in the oil and natural gas industry. These larger companies may have a greater ability to continue development activities during periods of low oil and natural gas prices and to absorb the burden of present and future federal, state, local and other laws and regulations. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

We may incur substantial additional debt to enable us to make our quarterly distributions, which may negatively affect our ability to execute our business plan and make future distributions.

We may be unable to make a distribution at the initial distribution rate or the then-current distribution rate without incurring indebtedness. When we borrow to make distributions, we are distributing more cash than we are generating from our operations on a current basis. This means that we are using a portion of our borrowing capacity under our revolving credit facility to make distributions rather than to maintain or expand our operations. If we use borrowings under our revolving credit facility to make distributions for an extended period of time rather than toward funding capital expenditures and other matters relating to our operations, we may be unable to support or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness to make these distributions, will reduce our cash available for distribution on our units and will have a material adverse effect on our business, financial condition and results of operations. If we borrow to make distributions during periods of low commodity prices and commodity prices remain low, we may have to reduce our distribution in order to avoid excessive leverage.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities and may affect our ability to make future distributions.

As of December 31, 2008, we had approximately $31.3 million of debt. We may incur additional debt in the future. Our future indebtedness could have important consequences to us, including:

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

•

covenants contained in our future debt arrangements may require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

•

we may need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

•

our debt level may make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing our indebtedness or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.

There are a variety of operating risks inherent in our wells, gathering systems, pipelines, transportation, storage, transloading and other facilities, such as leaks, accidents, fires, explosions, mechanical problems, hurricanes, adverse weather conditions, hazardous materials releases, mechanical failures and other events beyond our control, all of which could cause substantial financial losses. Any of these or other similar occurrences could result in the disruption of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, fines, environmental pollution, impairment of our operations and substantial revenue losses. The location of our facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks. As a result of the foregoing, we are, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business.

We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. We may also elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Changes in the insurance markets due to terrorist attacks and hurricanes have made it more difficult for us to obtain certain types of coverage. We may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and our insurance may contain large deductibles or fail to cover certain hazards or cover all potential losses. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Our business depends in part on gathering and transportation facilities owned by others. Any limitation in the availability of those facilities could interfere with our ability to market our oil and natural gas production and could harm our business.

The marketability of our oil and natural gas production depends in part on the availability, proximity and capacity of pipelines, oil and natural gas gathering systems and processing facilities. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or pipeline capacity could reduce our ability to market our oil and natural gas production and harm our business.

We have limited control over the activities on properties we do not operate.

Other companies operated approximately 17.4% of our wells on a pro forma basis as of December 31, 2008. We have limited ability to influence or control the operation or future development of these non-operated properties or the amount of capital expenditures that we are required to fund with respect to them. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.

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

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. Environmental and other governmental laws and regulations have increased the costs to plan, design, drill, install, operate and abandon oil and natural gas wells and related pipeline and processing facilities. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and production of, oil and natural gas. Failure to comply with such laws and regulations, as interpreted and enforced, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions to our unitholders.

Our pipeline integrity program may subject us to significant costs and liabilities.

As a result of pipeline integrity testing under the Pipeline Safety Improvement Act of 2002, we may incur significant and unanticipated operating and capital expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines. Furthermore, the Act or an increase in public expectations for pipeline safety may require additional reporting, the replacement of our pipeline segments, additional monitoring equipment and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the U.S. Department of Transportation rules and related regulations and orders, we could be subject to penalties and fines, which could have a material adverse effect on our ability to make distributions to our unitholders.

Our business would be adversely affected if operations at our terminaling, transportation and distribution facilities experienced significant interruptions. Our business would also be adversely affected if the operations of our customers and suppliers experienced significant interruptions.

Our operations are dependent upon our terminaling and storage facilities and various means of transportation. We are also dependent upon the uninterrupted operations of certain facilities owned or operated by our suppliers and customers. Any significant interruption at these facilities or inability to transport products to or from these facilities or to or from our customers for any reason would adversely affect our results of operations, cash flow and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities. Operations at our facilities and at the facilities owned or operated by our suppliers and customers could be partially or completely shut down, temporarily or permanently, as the result of any number of circumstances that are not within our control, such as:

	•		weather conditions;
	•		environmental remediations;
	•		labor difficulties; and
	•		disruptions in the supply of our products to our facilities or means of transportation.

In addition, terrorist attacks and acts of sabotage could target oil and gas production facilities, refineries, processing plants, terminals and other infrastructure facilities. Any significant interruptions at our facilities, facilities owned or operated by our suppliers or customers, or in the oil and gas industry as a whole caused by such attacks or acts could have a material adverse affect on our results of operations, cash flow and ability to make distributions to our unitholders or to make principal and interest payments on our debt securities.

The occurrence or threat of extraordinary events, including domestic and international terrorist attacks, and laws and regulations related thereto may disrupt our operations and decrease demand for our products and services.

Chemical-related assets, such as those handled at our terminaling and storage facilities, may be at greater risk of future terrorist attacks than other possible targets in the United States. Federal legislation is under consideration that could impose new site security requirements, specifically on chemical facilities, which may increase our overhead expenses. Our business or our customers’ businesses could be adversely affected because of the cost of complying with new security regulations.

New federal regulations have already been adopted to increase the security of the transportation of hazardous chemicals in the United States. We believe we have met these requirements but additional federal and local regulations that limit the distribution of hazardous materials are being considered. We store, ship and receive materials that are classified as hazardous. Bans on movement of hazardous materials through certain cities could affect the efficiency of our logistical operations. Broader restrictions on hazardous material movements could lead to additional investment to produce hazardous raw materials and change where and what products we provide and transport.

The occurrence of extraordinary events, including future terrorist attacks and the outbreak or escalation of hostilities, cannot be predicted, and their occurrence can be expected to continue to affect negatively the economy in general, and specifically the markets for our products. The resulting damage from a direct attack on our assets, or assets used by us, could include loss of life and property damage. In addition, available insurance coverage may not be sufficient to cover all of the damage incurred or, if available, may be prohibitively expensive.

We are subject to many environmental and safety regulations that may result in significant unanticipated costs or liabilities or cause interruptions in our operations.

Our operations involve the handling, production, transportation, treatment and disposal of materials that are classified as hazardous or toxic and that are extensively regulated by environmental and health and safety laws, regulations and permit requirements. We may incur substantial costs, including fines, damages and criminal or civil sanctions, or experience interruptions in our operations for actual or alleged violations or compliance requirements arising under environmental laws, any of which could have a material adverse effect on our business, financial condition, results of operations or cash flows. Our operations could result in violations of environmental laws, including spills or other releases of hazardous substances to the environment. In the event of a catastrophic incident, we could incur material costs. Furthermore, we may be liable for the costs of investigating and cleaning up environmental contamination on or from our properties or at off-site locations where we disposed of or arranged for the disposal or treatment of hazardous materials. We own or lease a number of properties that have been used to store or distribute refined products for many years. Many of these properties, such as the assets acquired from Regional Enterprises, Inc. in 2007 and the Oklahoma assets, were operated by third parties whose handling, disposal, or release of hydrocarbons and other wastes was not under our control. If significant previously unknown contamination is discovered, or if existing laws or their enforcement change, then the resulting expenditures could have a material adverse effect on our business, financial condition, results of operations or cash flows.

Environmental, health and safety laws, regulations and permit requirements, and the potential for further expanded laws, regulations and permit requirements may increase our costs or reduce demand for our products and thereby negatively affect our business. Environmental permits required for our operations are subject to periodic renewal and may be revoked or modified for cause or when new or revised environmental requirements are implemented. Changing and increasingly strict environmental requirements and the potential for further expanded regulation may increase our costs and can affect the manufacturing, handling, processing, distribution and use of our products. If so affected, our business and operations may be materially and adversely affected. In addition, changes in these requirements may cause us to incur substantial costs in upgrading or redesigning our facilities and processes, including our waste treatment, storage, disposal and other waste handling practices and equipment. For these reasons, we may need to make capital expenditures beyond those currently anticipated to comply with existing or future environmental or safety laws.

We store and transport hazardous or volatile chemicals at some of our facilities. If our safety procedures are not effective, an accident involving these other hazardous or volatile chemicals could result in serious injuries or death, or result in the shutdown of our facilities.

We store and transport hazardous chemicals such as aqua ammonia, phosphoric acid, hydrochloric acid and sulfuric acid. An accident involving any of these chemicals could result in serious injuries or death, or evacuation of areas near an accident. An accident could also result in third-party property damage or shutdown of our terminaling facilities, or cause us to expend significant amounts to remediate safety issues or to repair damaged facilities. As a result, an accident involving any of these chemicals could have a material adverse effect on our results of operations, liquidity or financial condition.

Risks Inherent in an Investment in Us

The amount of cash distributions that we will be able to distribute to unitholders will be reduced by the costs associated with general and administrative expenses and reserves that our General Partner believes prudent to maintain for the proper conduct of our business and for future distributions.

Before we can pay distributions to our unitholders, we must first pay or reserve cash for our expenses, including capital expenditures and the costs of being a public company and other operating expenses, and we may reserve cash for future distributions during periods of limited cash flows. The amount of cash we have available for distribution to our unitholders will be affected by our level of reserves and expenses. Because of restrictions in our credit agreements and lack of available cash, we have not made distributions for the quarters ended September 30, 2008 and December 31, 2008.

Our General Partner and its affiliates own a controlling interest in us and may have conflicts of interest with us and limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of our unitholders.

Penn Octane Corporation controls our General Partner, which controls us. The managers and officers of our General Partner have a fiduciary duty to manage our General Partner in a manner beneficial to Penn Octane. Furthermore, certain managers and officers of our General Partner may be directors or officers of affiliates of our General Partner, including Penn Octane. Conflicts of interest may arise between Penn Octane and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These potential conflicts include, among others, the following situations:

•

neither our partnership agreement nor any other agreement requires Penn Octane or its affiliates (other than our General Partner) to pursue a business strategy that favors us. Penn Octane’s directors and officers have a fiduciary duty to make these decisions in the best interests of its unitholders, which may be contrary to our interests;

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our General Partner is allowed to take into account the interests of parties other than us, such as Penn Octane, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders;

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Penn Octane is not limited in its ability to compete with us and is only obligated to provide us with the services and personnel required by the Omnibus Agreement;

•

under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner or its affiliates (including Penn Octane) and no such person who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for our partnership will have any duty to communicate or offer such opportunity to us;

•

some officers of our General Partner who provide services to us devote time to affiliates of our General Partner and may be compensated for services rendered to such affiliates;

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our General Partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

•

our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

•

our General Partner may cause us to borrow funds in order to permit the payment of cash distributions;

	•		our General Partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
	•		our General Partner may cause us to purchase common units;

•

our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates; and

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our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

Penn Octane is not limited in its ability to compete with us, which could limit our ability to acquire additional assets or businesses.

Our partnership agreement does not prohibit Penn Octane from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, Penn Octane may acquire, develop or dispose of additional oil and natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

Penn Octane, which controls our General Partner, has the power to appoint and remove the members of the board of managers of our General Partner.

Because Penn Octane controls our General Partner, it has the ability to elect all of the members of the board of managers of our General Partner. Our General Partner has control over all decisions related to our operations. Furthermore, the goals and objectives of Penn Octane and our General Partner relating to us may not be consistent with those of a majority of the public unitholders.

We are primarily dependent on officers of our General Partner to manage our operations. Failure of such officers to devote sufficient attention to the management and operation of our business may adversely affect our financial results and our ability to make distributions to our unitholders.

The officers of our General Partner are primarily responsible for managing our business and operations. We do not maintain key person life insurance policies on any personnel. Although our General Partner has arrangements relating to compensation and benefits, our General Partner does not have any employment contracts or other agreements with such officers binding them to provide services for any particular term. The loss of the services of any of these individuals, including Messrs. Bothwell and Manner could have a material adverse effect on our business and our ability to make distributions to our unitholders.

Our partnership agreement limits our General Partner’s fiduciary duties to unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

•

permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

•

provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of managers of our General Partner acting in good faith and not involving a vote of unitholders must be “fair and reasonable” to us, as provided by the partnership agreement. In determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

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provides that our General Partner and its officers and managers will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officers and managers acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•

provides that in resolving conflicts of interest, it will be presumed that in making its decision the General Partner or its conflict committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a unitholder will become bound by the provisions in the partnership agreement, including the provisions discussed above.

Unitholders have limited voting rights and are not entitled to elect our General Partner or its managers.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our General Partner or its board of managers on an annual or other continuing basis. The board of managers of our General Partner will be chosen by Penn Octane. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if unitholders are dissatisfied, it would be difficult to remove our General Partner.

The vote of the holders of at least 80% of all outstanding units voting together as a single class is required to remove the General Partner. Therefore, even if the unitholders are dissatisfied it would be difficult to remove our General Partner.

Control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its General Partner interest to a third party for any reason without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Penn Octane, the owner of our General Partner, from transferring all or a portion of its ownership interest in our General Partner to a third party. The new owner of our General Partner would then be in a position to replace the board of managers and officers of our General Partner with its own choices and thereby influence the decisions made by the board of managers and officers.

We may issue additional units, including units that are senior to the common units, without unitholder approval, which would dilute the ownership interests of our existing unitholders.

Our partnership agreement does not limit the number of additional partner interests that we may issue. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

	•		our unitholders’ proportionate ownership interest in us will decrease;
	•		the amount of cash available for distribution on each unit may decrease;
	•		the ratio of taxable income to distributions may increase;
	•		the relative voting strength of each previously outstanding unit may be diminished; and
	•		the market price of the common units may decline.

Our partnership agreement restricts the voting rights of unitholders, other than our General Partner and its affiliates, owning 20% or more of our common units, which may limit the ability of significant unitholders to influence the manner or direction of management.

Our partnership agreement restricts unitholders’ voting rights by providing that any common units held by a person, entity or group that owns 20% or more of any class of common units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such common units with the prior approval of the board of managers of our General Partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting unitholders’ ability to influence the manner or direction of management.

The liability of our unitholders may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for our obligations as if they were a general partner if:

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a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•

their right to act with other unitholders to remove or replace the General Partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to such purchaser of common units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Unitholders who are not “Eligible Holders” will not be entitled to receive distributions on or allocations of income or loss on their common units and their common units will be subject to redemption.

In order to comply with U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands, we have adopted certain requirements regarding those investors who may own our common units. As used herein, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands. As of the date hereof, Eligible Holder means:

	•		a citizen of the United States;
	•		a corporation organized under the laws of the United States or of any state thereof;
	•		a public body, including a municipality; or

•

an association of United States citizens, such as a partnership or limited liability company, organized under the laws of the United States or of any state thereof, but only if such association does not have any direct or indirect foreign ownership, other than foreign ownership of stock in a parent corporation organized under the laws of the United States or of any state thereof.

For the avoidance of doubt, onshore mineral leases or any direct or indirect interest therein may be acquired and held by aliens only through stock ownership, holding or control in a corporation organized under the laws of the United States or of any state thereof. Unitholders who are not persons or entities who meet the requirements to be an Eligible Holder, will not receive distributions or allocations of income and loss on their common units and they run the risk of having their common units redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.

An increase in interest rates may cause the market price of our common units to decline.

Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded limited partner interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

Risks Related to Tax Matters

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes or we were to become subject to additional entity-level taxation for state tax purposes, then our cash available for distribution would be substantially reduced.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we will be treated as a corporation for federal income tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. For example, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our units.

In addition, because of widespread state budget deficits and other reasons, several states, including Texas, are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, margin and other forms of taxation. For example, beginning in 2008, we have become subject to a new entity level tax on any portion of our income that is generated in Texas. Specifically, the Texas margin tax is imposed at a maximum effective rate of 0.7% of our gross income that is apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to our unitholders.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first business day of each month, instead of on the basis of the date a particular unit is transferred. The use of this method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

An IRS contest of our federal income tax positions may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our General Partner because the costs will reduce our cash available for distribution.

Our unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, our unitholders may be required to pay any federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.

Tax gain or loss on disposition of common units could be more or less than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of unitholders’ allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depletion, intangible drilling costs and depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their common units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file United States federal tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will take depletion, depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders tax returns.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve-month period, holders of our subordinated and common units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and unitholders receiving two Schedule K-1s, for one fiscal year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

Unitholders will likely be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Furthermore, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and do business in Oklahoma. Oklahoma currently imposes a personal income tax. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax or that impose entity level taxes to which we could be subject. It is our unitholders’ responsibility to file all United States federal, foreign, state and local tax returns.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the General Partner and the unitholders. The IRS may successfully challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and the holders of the incentive distribution rights. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the General Partner, which may be unfavorable to such unitholders. Moreover, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the General Partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Item 1B. Unresolved Staff Comments.

None.

Item 3. Legal Proceedings.

Penn Octane, Rio Vista and/or Rio Vista’s subsidiaries were named as defendants in two lawsuits filed in connection with an accident in the town of Lucio Blanco, Mexico on August 11, 2005, involving a tanker truck carrying LPG which was struck by a train resulting in an explosion. None of Penn Octane, Rio Vista or any of Rio Vista’s subsidiaries owned or operated the tanker truck or employed or controlled the driver of the tanker truck. Furthermore, none of Penn Octane, Rio Vista or any of Rio Vista’s subsidiaries owned or had custody of the LPG on the tanker truck at the time and location of the accident.

The tanker truck reportedly took delivery of LPG at the Matamoros Terminal Facility operated under agreement with Rio Vista’s Mexican subsidiaries. According to the lawsuits, after leaving the Matamoros Terminal Facility, the tanker truck was involved in a collision with a train in Lucio Blanco, Mexico, resulting in a tragic explosion that killed and injured several persons and caused significant property damage. Published reports indicate that the truck used a road not approved for large trucks and failed to stop at an unprotected rail crossing, resulting in the collision and explosion. The insurance carrier for the owner of the tanker truck has settled certain claims in Mexico with victims of the accident.

Even though the accident took place in Mexico, these lawsuits were filed in Texas. The first case is captioned Lesly Camacho by Her Mother Dora Adame as Next Friend, et al. vs. Penn Octane International LLC, et al and was filed in the 404 ^th Judicial District Court for Cameron County, Texas on September 26, 2005. The plaintiffs seek unspecified monetary damages. On August 16, 2006 with the consent of the parties, the Court issued an amended order for temporary injunction for the purpose of preserving relevant evidence. The amended injunction required a subsidiary of Rio Vista to make available for inspection by plaintiffs Rio Vista’s terminal facilities in Brownsville, Texas and Matamoros, Mexico and associated equipment and records. The order also required Rio Vista to give 30 days advance notice to plaintiffs before conducting any alteration, repair, service, work or changes to the facilities or equipment. In addition, the order required Rio Vista to make available its employees for deposition by the plaintiffs and to secure and preserve certain physical evidence believed to be located in Mexico. The Brownsville, Texas terminal facility was sold to TransMontaigne Product Services Inc. on August 22, 2006. In January 2007, this case was removed to the U.S. District Court for the Southern District of Texas, Brownsville Division. In July 2007, the case was remanded to the state court in Cameron County, Texas. In August 2007, plaintiffs filed an amended petition alleging that defendants delivered the LPG to an unqualified driver and that defendants failed to properly odorize the LPG before delivery.

In December of 2008, one of the insurance carriers, Ace Insurance, tendered its limit of one million in settlement of all claims brought by American citizens who were injured in the explosion. Those claims were dismissed. The legal damages that can be recovered by the remaining plaintiffs will be governed by Mexican law, which provides limited, scheduled recovery. This is deemed favorable to Rio Vista. Rio Vista’s legal fees and settlement costs were covered by insurance.

Since that settlement the remaining insurance carrier was Lexington Insurance Company (Lexington). On December 13, 2007, Lexington Insurance Company (Lexington) filed a declaratory action complaint against Penn Octane, Rio Vista and their related entities in the United States District Court in the Southern District of Texas (Brownsville) requesting the US Federal Court to rule that the plaintiff has no obligation to defend Penn Octane and the Rio Vista related entities in the Camacho litigation based on alleged coverage exceptions. Federal jurisdiction was contested and the case moved to state court. In a subsequent pleading, Lexington assumed the defense of Penn Octane and Rio Vista. However, there remains undetermined the obligation by Lexington to provide indemnification to Penn Octane and Rio Vista from any judgment resulting from the Camacho suit. Cross motions for summary judgment were filed by the parties, and the court ruled that the insurance policy issued by Lexington did cover the incident which occurred in Mexico. Lexington has subsequently filed a Notice of Appeals, and is proceeding to appeal the trial court’s ruling. Nevertheless, Lexington continued to provide a defense to Rio Vista in the Camacho case. As the cash currently stands, the trial court has ruled that insurance coverage does exist to provide coverage in the Camacho case.

The Camacho case is not presently set for trial. It is anticipated that a small group of plaintiffs will be identified by the court, and that group will be set for trial. It is anticipated that the trial group will not be set until the fall of 2009. No judgment following that trial will become final until all plaintiffs have gone to trial.

Management believes the remaining lawsuit against Penn Octane, Rio Vista and/or Rio Vista’s subsidiaries relating to the accident in Lucio Blanco is without merit and, based on the advice of counsel, does not anticipate liability for damages in excess of anticipated insurance coverage. The Company’s insurance carrier is expected to bear the legal fees and expenses in connection with defending this case. If, however, a court found liability on the part of Penn Octane, Rio Vista or their subsidiaries, a judgment or settlement in excess of insurance coverage could have a material adverse effect on Penn Octane’s and Rio Vista’s business, financial condition and results of operations.

On November 20, 2007, Rio Vista, Rio Vista Penny, LLC, Gary Moores, Bill Wood and GM Oil Properties, Inc. (GM) jointly filed an action for declaratory relief against Energy Spectrum Advisors, Inc. (Energy Spectrum) in the District Court of McIntosh County, Oklahoma. This action was filed in response to Energy Spectrum’s assertion that Rio Vista, Rio Vista Penny, LLC, as well as GM owed Energy Spectrum a commission based on Rio Vista Penny, LLC’s November, 2007 purchase of certain assets from GM. Energy Spectrum counterclaimed asserting that Rio Vista and Rio Vista Penny tortiously interfered with the commission agreement between Energy Spectrum and GM. Neither Rio Vista nor Rio Vista Penny were parties to this agreement. Management believes that the Rio Vista entities should have no liability for any commission obligation that GM may owe to Energy Spectrum. However the outcome of litigation cannot reliably be predicted. Discovery in the case is ongoing. No trial date has been set.

On August 19, 2008, Rio Vista, Rio Vista GP LLC, Rio Vista Penny LLC, Jerome B. Richter and Douglas G. Manner (Defendants) were named in a lawsuit filed by Northport Production Company and Eugene A. Viele (Plaintiffs). Mr. Viele is currently a director of Penn Octane Corporation and is also the principal owner of Northport Production Company. Mr. Manner currently serves as a director of Penn Octane Corporation and the General Partner. Plaintiffs allege breach of contract, negligent misrepresentation, and fraud in connection with the acquisition of the Oklahoma Assets. Plaintiffs are seeking judgment for compensatory damages of $487,000 and exemplary damages of not less than $200,000 as well as attorneys’ fees and other such relief as may be shown. Discovery is currently pending. Rio Vista believes that the liability, if any, ultimately resulting from this lawsuit should not materially affect its consolidated financial results.

Rio Vista and its subsidiaries are involved with other proceedings, lawsuits and claims in the ordinary course of its business. Rio Vista believes that the liabilities, if any, ultimately resulting from such proceedings, lawsuits and claims should not materially affect its consolidated financial results.

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

None.

PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

Rio Vista’s common units began trading on the NASDAQ National Market under the symbol “RVEP” on October 1, 2004.

The following table sets forth the reported high ask and low bid quotations of the common units for the periods indicated. Such quotations reflect inter-dealer prices, without retail mark-ups, mark-downs or commissions and may not necessarily represent actual transactions.

		LOW				HIGH
The year ended December 31, 2008:
First Quarter		$	12.06			$	17.25
Second Quarter			9.36				13.83
Third Quarter			8.00				13.00
Fourth Quarter			0.65				9.89

		LOW				HIGH
The year ended December 31, 2007:
First Quarter		$	5.34			$	9.54
Second Quarter			7.80				12.37
Third Quarter			10.50				23.00
Fourth Quarter			10.05				17.50

On March 30, 2009, the closing bid price of the common units as reported on the NASDAQ National Market was $0.64 per common unit. On March 30, 2009, Rio Vista had 2,762,463 common units outstanding and approximately 780 holders of record of the common units.

Rio Vista made the following distributions during the years ended December 31, 2007 and 2008:

										Amounts Paid
Quarter		Payment				Distribution				Common				General
Ended		Date				Per Unit				Units				Partner
Dec 2006			01/18/07			$	0.25			$	478,000			$	10,000
Mar 2007			05/04/07			$	0.25			$	478,000			$	10,000
Jun 2007			07/31/07			$	0.25			$	484,000			$	10,000
Sep 2007			11/14/07			$	0.25			$	484,000			$	10,000
Jun 2005 – Jun 2006 Arrearages			12/10/07			$	1.25			$	2,420,000			$	49,000
Dec 2007			02/14/08			$	0.25			$	607,000			$	12,000
Mar 2008			05/16/08			$	0.25			$	629,000			$	13,000
Jun 2008			08/14/08			$	0.25			$	679,000			$	14,000

The amount of the distributions paid through the June 2008 quarterly distribution represents the minimum quarterly distribution required to be made by Rio Vista pursuant to the partnership agreement. Rio Vista has not declared a distribution for the quarters ended September 30, 2008 and December 31, 2008.

Rio Vista does not anticipate making quarterly distributions during the year 2009. (See below under the heading “Distributions of Available Cash”).

Recent sales of Unregistered Securities

On February 15, 2007, the board of managers of our General Partner approved the grant of options to purchase a total of 21,250 common units under Rio Vista’s 2005 Equity Incentive Plan (2005 Plan). Of the total number of options granted, 5,000 were issued to an executive officer of our General Partner and 16,250 were issued to outside managers of our General Partner. The exercise price for the options is $8.38 per unit, which was the average of the high and low sale prices for Rio Vista common units as reported by the NASDAQ Stock Market on February 15, 2007. Options granted to the executive officer vest in equal monthly installments over a period of 36 months from the date of grant, become fully vested and exercisable upon a change in control event, and expire five years from the date of grant. Options granted to outside managers are fully vested on the date of grant and expire five years from the date of grant.

On March 21, 2007, the board of managers of our General Partner approved the grant of an option to purchase 20,000 common units of Rio Vista under the 2005 Plan to an executive officer of our General Partner. The exercise price for the options is $7.36 per unit, which was the average of the high and low sale prices for Rio Vista common units as reported by the NASDAQ Stock Market on March 21, 2007. The options vest in equal monthly installments over a period of 36 months from the date of grant, become fully vested and exercisable upon a change in control event, and expire five years from the date of grant.

On June 29, 2007, the board of managers of our General Partner approved the grant of an option to purchase 75,000 common units of Rio Vista under the 2005 Plan to an executive officer of our General Partner. The exercise price for the options is $11.21 per unit, which was the average of the high and low sale prices for Rio Vista common units as reported by the NASDAQ Stock Market on June 29, 2007. The options vest in equal monthly installments over a period of 36 months beginning January 1, 2007, become fully vested and exercisable upon a change in control event, and expires five years from the date of grant.

On June 29, 2007, the Board of Managers of our General Partner approved the grant of a restricted unit bonus of 25,000 common units under the 2005 Plan to an executive officer of our General Partner. The restricted unit bonus vested as to 8,334 units on July 1, 2007 and an additional 8,333 units on January 1, 2008, and the remaining units vest on July 1, 2008. In connection with the grant of restricted units, the Board of Managers also approved the payment to the executive officer of one or more cash bonuses in amounts sufficient, on an after-tax basis, to cover all taxes payable by the executive officer with respect the award of restricted units to him.

On July 27, 2007, in connection with the employment agreement with an executive of Regional, Rio Vista agreed to the grant of options to purchase a total of 25,000 common units under the 2005 Plan to the executive. The options will vest over a two year period.

On August 23, 2007, the board of managers of our General Partner approved the grant of options to purchase a total of 8,125 common units under the 2005 Plan to outside managers of our General Partner. The exercise price for the options is $15.15 per unit, which was the average of the high and low sale prices for Rio Vista common units as reported by the NASDAQ Stock Market on August 23, 2007. Options granted to outside managers are fully vested on the date of grant and expire five years from the date of grant.

On November 19, 2007, in connection with the acquisition of the Oklahoma assets, Rio Vista issued a total of 137,994 common units to the sellers of GO LLC and Penny Petroleum Corp. In addition, on November 19, 2007, Rio Vista issued the TCW Warrant to TCW see note I to the consolidated financial statements.

On November 29, 2007, in connection with a private placement, Rio Vista issued a total of 355,556 common units at a price of $11.25 per share to Standard General Fund L.P., Credit Suisse Management LLC and Structured Finance Americas LLC. The total purchase price of the common units was $4,000,000.

On January 23, 2008, the Board of Managers of our General Partner approved the grant of options to purchase a total of 16,250 common units under the 2005 Plan to certain outside members of the Board of Managers of our General Partner. The exercise price for the options is $14.42 per unit, which was the average of the high and low sale prices for Rio Vista common units as reported by the NASDAQ National Market on January 23, 2008. Options granted to outside managers are fully vested on the date of grant and expire five years from the date of grant.

On March 7, 2008, the Board of Managers of our General Partner approved the grant of a unit bonus of 8,812 common units under the 2005 Plan to an executive officer of our General Partner. The amount of units granted was based on the average of the high and low sale prices for Rio Vista common units as reported by the NASDAQ National Market on March 7, 2008.

On March 7, 2008, a total of 61,875 options to acquire common units of Rio Vista were exercised by holders of such warrants. Total proceeds received from the exercises were $774,000. In addition, on March 7, 2008, 15,625 options to acquire common units of Rio Vista were exercised by a holder through the offset of a severance obligation in connection with that employee’s termination.

On July 23, 2008, a total of 6,378 common units of Rio Vista were issued to CEOcast in connection with a consulting agreement. Based on the closing price of Rio Vista’s common units on July 22, 2008, the total amount recorded as an expense on the issuance date was $80,000.

On July 23, 2008, the board of managers authorized the issuance and sale by Rio Vista of 197,628 of Rio Vista’s common units to Penn Octane at $10.12 per unit, and Penn Octane’s board authorized its purchase of such Rio Vista units at that price, for an aggregate price of approximately $2,000,000.   The price per unit was the closing price for Rio Vista common units on May 30, 2008 as reported by the NASDAQ National Market (see note M to the consolidated financial statements).

On May 28, 2008, Rio Vista and Strategic Growth International (SGI), entered into a one year consulting agreement whereby SGI has agreed to provide public relations consulting services. The agreement could be cancelled after 6 months and was cancelled on October 29, 2008 with an effective date of December 1, 2008. In connection with the agreement, Rio Vista granted SGI 50,000 warrants to purchase common units of Rio Vista at an exercise price of $12.00 per common unit. The warrants cannot be exercised for one year from the date of issuance and the warrants will expire three years from the date of issuance. Total cost recorded at the grant date was $161,000. As a result of the aforementioned cancellation, the number of warrants granted was reduced to 25,000.

During June 2008, the Board of Managers of the General Partner of Rio Vista approved an employment agreement with an officer of the General Partner. Under the terms of the employment agreement, the officer is entitled to receive a grant of 30,000 restricted common units under Rio Vista’s 2005 Equity Incentive Plan in accordance with the following vesting schedule: 5,000 common units after the officer has been employed for six months, another 5,000 common units after one year of employment, another 10,000 common units after two years of employment and another 10,000 common units after three years of employment. The common units were granted on October 17, 2008. Total compensation cost recorded under the aforementioned grant was approximately $205,000 of which $34,000 was expensed during the year ended December 31, 2008.

On October 17, 2008, Rio Vista issued an aggregate of 12,939 Rio Vista common units in satisfaction of all liquidated damages due to Standard General. (see note I to the consolidated financial statements).

The above issuances were exempt from registration under the Securities Act of 1933 pursuant to Section 4(2) thereof because the issuances did not involve any public offering of securities.

Item 6. Selected Financial Data.

Not applicable.

Item 7 . Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion of Rio Vista’s liquidity and capital resources should be read in conjunction with the consolidated financial statements of Rio Vista and related notes thereto appearing elsewhere herein. References to specific years preceded by “fiscal” (e.g. fiscal 2008) refer to Rio Vista’s fiscal year ending December 31.

Overview

Historical Assets and Operations

In August 2006, Rio Vista completed the disposition of substantially all of its U.S. LPG assets to TransMontaigne, including the Brownsville, Texas terminal facility and refined products tank farm, together with associated improvements, leases, easements, licenses and permits; an LPG sales agreement; and all of LPG inventory. In December 2007, Rio Vista completed the disposition of its remaining LPG assets to TransMontaigne, including the U.S. portion of the two pipelines from a Brownsville, Texas terminal owned by TransMontaigne to the U.S. border, along with all associated rights-of-way and easements; all of the outstanding equity interests in entities owning interests in the portion of the two pipelines that extend from the U.S. border to Matamoros, Mexico; and all of the rights for indirect control of an entity that owns a terminal site in Matamoros, Mexico. As a result, effective January 1, 2008, Rio Vista no longer operates the assets associated with the LPG business it had historically conducted.

Current Assets and Operations

In July 2007, Rio Vista acquired Regional and in November 2007, Rio Vista acquired certain oil and natural gas producing properties and related assets in the State of Oklahoma formerly owned by GM Oil Properties, Inc., Penny Petroleum Corporation and GO LLC. As a result of these acquisitions in 2007, Rio Vista is now focused on the acquisition, development and production of oil and natural gas properties and related midstream assets, and the operation and development of Regional’s business consisting of transportation and terminaling. Beginning March 1, 2008, Rio Vista Operating LLC (Operating) became the operator of the Oklahoma Assets.

The above acquisitions were funded by a combination of debt (new and assumed), private placements of Rio Vista common units and proceeds from the sale of Rio Vista’s LPG related assets.  During November 2007, Rio Vista completed a private placement of common units raising gross proceeds of $4.0 million (see note I to the consolidated financial statements).

Results of Operations

Because of the sale of the LPG sales business during August 2006, which at that time was our sole business up through the date of the sale, the commencement and sale of our LPG Transportation business during August 2006 and December 2007, respectively, and our rapid growth through the acquisitions of Regional and the Oklahoma Assets during 2007, our historical results of operations and period-to-period comparisons of these results during the years ended 2006, 2007 and 2008 are not that meaningful or indicative of future results.

The results of operations from continuing operations during the years ended December 2007 and 2008 reflect the results associated with the i.) the Transportation and Terminaling Business associated with bulk and petroleum products associated with Regional operations which was acquired during July 2007 and LPG, which was commenced during August 2006 and was sold on December 31, 2007 (including all costs associated with operation of the US-Mexico Pipelines and Matamoros Terminal Facility), ii.) the operation of the Oklahoma Assets, which was acquired during November 2007 and iii.) all indirect income and expenses of Rio Vista.

Continuing Operations

Year Ended December 31, 2008 Compared With Year Ended December 31, 2007

		YEAR ENDED DECEMBER 31, 2008
		Oklahoma				Regional				LPG				Corporate/
		Assets (a)				Enterprises (b)				Transportation (c)				Other				Total
Revenues		$	5,247,000			$	8,573,000			$	—			$	1,000			$	13,821,000
Cost Of Goods Sold			4,322,000				6,444,000				—				(8,000	)			10,758,000
Gross Profit			925,000				2,129,000				—				9,000				3,063,000
Selling, General And Administrative Expenses			493,000				1,167,000				—				3,650,000				5,310,000
Loss on sale of remaining LPG-related assets			—				—				351,000				—				351,000
Operating Income			432,000				962,000				(351,000	)			(3,641,000	)			(2,598,000	)
Other Income (Expense)
Interest Expense			(2,849,000	)			(631,000	)			—				(178,000	)			(3,658,000	)
Interest Income			7,000				—				—				1,000				8,000
Income (loss) from Continuing Operations Before Taxes			(2,410,000	)			331,000				(351,000	)			(3,818,000	)			(6,248,000	)
Provision (Benefit) For Income Taxes			(103,000	)			66,000				—				—				(37,000	)
Income (loss) From Continuing Operations		$	(2,307,000	)		$	265,000			$	(351,000	)		$	(3,818,000	)		$	(6,211,000	)

		YEAR ENDED DECEMBER 31, 2007
		Oklahoma				Regional				LPG				Corporate/
		Assets (a)				Enterprises (b)				Transportation (c)				Other				Total
Revenues		$	527,000			$	3,038,000			$	2,341,000			$	—			$	5,906,000
Cost Of Goods Sold			390,000				2,399,000				1,971,000				45,000				4,805,000
Gross Profit			137,000				639,000				370,000				(45,000	)			1,101,000
Selling, General and Administrative Expenses			41,000				363,000				258,000				4,008,000				4,670,000
Loss on sale of remaining LPG-related assets			—				—				406,000				—				406,000
Operating Income (loss)			96,000				276,000				(294,000	)			(4,053,000	)			(3,975,000	)
Other Income (Expense)
Interest Expense			(275,000	)			(322,000	)			(281,000	)			(7,000	)			(885,000	)
Interest Income			—				14,000				1,000				2,000				17,000
Loss From Continuing Operations Before Taxes			(179,000	)			(32,000	)			(574,000	)			(4,058,000	)			(4,843,000	)
Provision (Benefit) For Income Taxes			(4,000	)			(51,000	)			34,000				—				(21,000	)
Income (loss) From Continuing Operations		$	(175,000	)		$	19,000			$	(608,000	)		$	(4,058,000	)		$	(4,822,000	)