Use these links to rapidly review the document
Table of Contents
INDEX TO FINANCIAL STATEMENTS
As filed with the Securities and Exchange Commission on February 14, 2008
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form S-1
REGISTRATION STATEMENT
UNDER THE SECURITIES ACT OF 1933
Venoco Acquisition Company, L.P.
(Exact Name of Registrant as Specified in Its Charter)
Delaware (State or Other Jurisdiction of Incorporation or Organization) | | 1311 (Primary Standard Industrial Classification Code Number) | | 65-1320326 (I.R.S. Employer Identification Number) |
370 17th Street, Suite 3900
Denver, Colorado 80202-1370
(303) 626-8300
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
Timothy Marquez
Chairman and Chief Executive Officer
370 17th Street, Suite 3900
Denver, Colorado 80202-1370
(303) 626-8300
(Name, Address, Including Zip Code, and Telephone Number,
Including Area Code, of Agent for Service)
Copies to: |
Alan P. Baden Gillian A. Hobson Vinson & Elkins L.L.P. First City Tower 1001 Fannin Street, Suite 2500 Houston, Texas 77002-6760 Telephone: (713) 758-2222 | | J. Michael Chambers J. Vincent Kendrick Akin Gump Strauss Hauer & Feld LLP 1111 Louisiana Street, 44th Floor Houston, Texas 77002 Telephone: (713) 220-5800 |
Approximate date of commencement of proposed sale to the public:As soon as practicable after this Registration Statement becomes effective.
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o
Indicate by check mark whether the registrant is a large accelerated file, an accelerated file, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filed," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o | | Accelerated filer o |
Non-accelerated filer ý (Do not check if a smaller reporting company) | | Smaller reporting company o |
CALCULATION OF REGISTRATION FEE
|
Title of Each Class of Securities To Be Registered
| | Proposed Maximum Aggregate Offering Price(1)(2)
| | Amount of Registration Fee
|
---|
|
Common units representing limited partner interests | | $209,300,000 | | $8,226 |
|
- (1)
- Includes common units issuable upon exercise of the underwriters' option to purchase additional common units.
- (2)
- Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.
Subject to Completion, dated February 14, 2008
The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.
PROSPECTUS

9,100,000 Common Units
Representing Limited Partner Interests
Venoco Acquisition Company, L.P. is a Delaware limited partnership formed on September 25, 2007 by Venoco, Inc. (NYSE: VQ) to acquire, exploit, develop and produce oil and natural gas properties. This is the initial public offering of our common units. We expect the initial public offering price to be between $ and $ per unit. No public market currently exists for our common units. We intend to apply to list our common units on the New York Stock Exchange under the symbol "VAC."
Investing in our common units involves risks. Please read "Risk Factors"
beginning on page 17.
These risks include the following:
- •
- We may not have sufficient cash flow from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements and other payments to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.
- •
- The amount of cash we have available for distribution to holders of our units depends on our cash flow. On a pro forma basis, we would not have had sufficient cash available for distribution to pay the minimum quarterly distribution on all units for the year ended December 31, 2006 or any distribution on our units for the twelve months ended September 30, 2007.
- •
- Oil and natural gas prices are currently at historically high levels and are very volatile. A sustained decline in these commodity prices will cause a decline in our cash flow from operations, which may cause us to reduce our distributions or cease paying distributions altogether.
- •
- If Venoco does not present us with attractive acquisition opportunities, we may not be able to maintain or increase our asset base, which would adversely affect our cash from operations and our ability to make distributions.
- •
- Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with us and have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of our common unitholders. Our partnership agreement limits the circumstances under which our common unitholders may make a claim relating to conflicts of interest and the remedies available to holders of units in that event.
- •
- Common unitholders will have limited voting rights and will not be entitled to elect our general partner or its directors.
- •
- Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, our cash available for distribution to you would be substantially reduced.
- •
- You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
In order to comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands and with certain Federal Energy Regulatory Commission requirements, we will require each owner of our units to be an "Eligible Holder." If you are not an Eligible Holder, you will not be entitled to receive distributions or allocations of income or loss on your common units, and your common units will be subject to redemption. Please read "The Partnership Agreement—Non-Eligible Holders; Redemption."
| | Per Common Unit
| | Total
|
---|
Initial public offering price | | $ | | | $ | |
Underwriting discount(1) | | $ | | | $ | |
Net proceeds to Venoco Acquisition Company, L.P. (before expenses) | | $ | | | $ | |
- (1)
- Excludes a structuring fee of $ payable to Lehman Brothers Inc. Please read "Underwriting" for more information.
We have granted the underwriters a 30-day option to purchase up to an additional 1,365,000 common units from us on the same terms and conditions as set forth above if the underwriters sell more than 9,100,000 common units in this offering.
Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.
Lehman Brothers, on behalf of the underwriters, expects to deliver the common units on or about , 2008.
LEHMAN BROTHERS | | CITI | | UBS INVESTMENT BANK |
, 2008
(Map of Partnership Properties)
Table of Contents
i
ii
You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date.
Until , 2008 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a
iii
prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read "Risk Factors" and "Forward-Looking Statements."
As used in this prospectus, unless we indicate otherwise: (1) "Venoco Acquisition Company," "the partnership," "we," "our," "us" or like terms when used in a historical context refer to the business that Venoco, Inc. is contributing to Venoco Acquisition Company, L.P. and when used in the present tense or prospectively refer to Venoco Acquisition Company, L.P. and its subsidiaries, (2) "Venoco Acquisition Company GP, LLC" or "our general partner" refer to Venoco Acquisition Company GP, LLC, our general partner, (3) "Venoco" refers to Venoco, Inc., the owner of our general partner, and its wholly owned subsidiaries, (4) "Partnership Properties" or "our properties" refer to the properties to be contributed to us by Venoco in connection with this offering and (5) the term "pro forma" refers to information presented after giving pro forma effect to the transactions described in "Prospectus Summary—Summary Historical and Pro Forma Financial and Operating Data." Our oil and natural gas reserve information as of December 31, 2006 included in this prospectus is based on evaluations prepared by our internal reserve engineers, which were derived from the external reserve reports prepared by our independent reserve engineers, or "Reserve Reports."
iv
PROSPECTUS SUMMARY
This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma combined financial statements and the notes to those financial statements. Unless otherwise indicated, the information presented in this prospectus assumes (i) an initial public offering price of $20.00 per unit and (ii) that the underwriters' option to purchase additional common units is not exercised. We have included a glossary of some of the oil and natural gas terms and partnership agreement terms used in this prospectus in Appendix B.
Venoco Acquisition Company, L.P.
We are a growth-oriented Delaware limited partnership formed by Venoco, Inc. (NYSE: VQ) to acquire, exploit, develop and produce oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are principally located in coastal California and onshore Texas. Most of our oil and natural gas properties are located in large, mature fields with well-known geologic characteristics and long production histories. Our properties generally have stable and predictable production profiles and long reserve lives.
As of December 31, 2006, the Partnership Properties, including reserves attributable to properties acquired by Venoco after that date, had estimated proved reserves of 21.2 MMBoe, of which 86.2% were oil and 81.1% were classified as proved developed, and had a reserve-to-production ratio of 15.1 years. As of September 30, 2007, the Partnership Properties consisted primarily of working interests in 325 gross producing wells, with a 38.5% average working interest. We operate interests that accounted for 80.8% of our pro forma production for the nine months ended September 30, 2007. The Partnership Properties represented 21.5% of Venoco's estimated proved reserves as of December 31, 2006. The Partnership Properties also include five associated oil or natural gas pipeline systems.
The following table summarizes information about our oil and natural gas properties by region:
| | Estimated Pro Forma Proved Reserves as of December 31, 2006
| | Pro Forma Average Daily Net Production for the Nine Months Ended September 30, 2007 (Boe/d)(1)
| |
| |
| |
---|
| | Pro Forma Reserve-to- Production Ratio (Years)(2)
| |
| |
---|
Region
| | Total (MMBoe)
| | % Developed
| | % Oil
| | Estimated Production Decline Rate(3)
| |
---|
California | | | | | | | | | | | | | |
| Coastal(4) | | 12.9 | | 70.9 | % | 88.0 | % | 2,346 | | 15.1 | | 8.2 | % |
| Other | | 1.4 | | 85.2 | % | — | | 239 | | 15.5 | | 9.2 | % |
Texas | | 6.9 | | 99.4 | % | 100.0 | % | 1,260 | | 15.0 | | 4.7 | % |
| |
| | | | | |
| | | | | |
Total | | 21.2 | | 81.1 | % | 86.2 | % | 3,845 | | 15.1 | | 7.2 | % |
| |
| | | | | |
| | | | | |
- (1)
- Production data for coastal California includes the results of the onshore portion of the West Montalvo field acquired by Venoco on May 11, 2007, as if the transaction had occurred on January 1, 2007.
- (2)
- The pro forma reserve-to-production ratio is calculated by dividing estimated pro forma proved reserves as of December 31, 2006 by the annualized pro forma average daily net production for the nine months ended September 30, 2007.
- (3)
- Represents the percentage decrease in annual production from the proved developed producing reserves of the Partnership Properties in 2009 when compared to 2008, as estimated in our Reserve Reports.
- (4)
- Includes onshore and offshore properties in southern California.
Our Relationship with Venoco, Inc.
One of our principal strengths is our relationship with Venoco, a publicly traded independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil
1
and natural gas properties in California and Texas. Venoco's pro forma estimated proved reserves as of December 31, 2006, including reserves attributable to properties acquired after that date and the Partnership Properties, were 98.6 MMBoe, of which 58.2% were oil and 57.9% were classified as proved developed. Venoco's average daily net production was 19,344 Boe/d for the nine months ended September 30, 2007.
Since its inception, Venoco has sought to acquire mature producing properties characterized by long reserve lives, well-established production histories, and predictable production profiles that exhibit relatively moderate production declines. Venoco has an established track record of successfully acquiring, owning and operating oil and natural gas properties located in California and Texas, our primary areas of operation. Since January 2005, Venoco has acquired properties with estimated proved reserves of approximately 46.1 MMBoe in 16 transactions.
Following its contribution of the Partnership Properties to us, Venoco will continue to own and operate oil and natural gas properties with exploitation and development opportunities that are, or after additional capital is invested may become, suitable for us. These properties include, among others, Venoco's significant remaining working interests in the South Ellwood field and in the Hastings Complex, two of the largest Partnership Properties.
Venoco views us as an integral part of its growth strategy, and we believe that it will be strongly incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. In addition to complementary business strategies and the proximity of our respective properties, Venoco will own a significant interest in us following the closing of this offering, including a 55.4% limited partner interest, as well as our general partner and all of our incentive distribution rights. However, we cannot say which assets, if any, Venoco may make available to us, or if we will pursue the opportunity to acquire those assets if they are made available to us. Furthermore, Venoco regularly evaluates acquisitions and dispositions and may elect to acquire or dispose of properties in the future without offering us the opportunity to participate in those transactions. Venoco has retained this flexibility because it believes that doing so is in the best interests of its stockholders. Moreover, after this offering, Venoco will continue to be free to act in a manner that is beneficial to its interests and detrimental to ours, which may include electing not to present us with future acquisition opportunities. Accordingly, while our relationship with Venoco and its subsidiaries is a significant strength, it also is a source of potential conflicts. Please read "Conflicts of Interest and Fiduciary Duties."
Business Strategy
Our primary business objectives are to generate stable cash flows that allow us to make quarterly cash distributions to our unitholders and to increase those distributions over time by executing the following business strategies:
- •
- Make accretive acquisitions of producing properties with long-lived, stable and predictable production profiles.
- •
- Increase our proved reserves and production through relatively low-risk exploitation and development activities.
- •
- Reduce the volatility in our cash flow through our commodity hedging activities.
Competitive Strengths
We believe that the following competitive strengths will enable us to achieve our primary business objectives and to successfully execute our strategies:
- •
- Our relationship with Venoco provides us with a number of competitive advantages, including:
- •
- the opportunity to acquire attractive assets directly from or jointly with Venoco, and
2
- •
- access to Venoco's substantial operating, technical and other expertise.
- •
- Our experienced management team has an established track record of successfully acquiring, exploiting and developing oil and natural gas properties.
- •
- Our oil and natural gas properties generally have stable and predictable production profiles with relatively moderate production declines, long reserve lives and well-established production histories.
- •
- Our geographically diverse oil and natural gas properties are located in established, mature producing basins.
- •
- We operate substantially all of our properties.
Hedging
As part of our business strategy, we intend to enter into hedging arrangements in the future with respect to at least 70% of the expected production from our proved developed producing reserves over a three- to five-year period in order to reduce our exposure to fluctuations in the prices of oil and natural gas. Our hedging arrangements will be designed to remove a significant portion of price volatility associated with our future oil and natural gas production. Our hedging arrangements will not eliminate the effects of changing oil and natural gas prices on our cash flows from operations for those periods. For more information on our expected hedging arrangements, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk."
Summary Risk Factors
An investment in our common units involves risks associated with our business, our limited partnership structure and the tax characteristics of our common units. Please read "Risk Factors" for a discussion of some of these risks.
Management of Venoco Acquisition Company, L.P.
Venoco Acquisition Company GP, LLC, our general partner, will manage our operations and activities, and its board of directors and officers will make decisions on our behalf. Timothy Marquez, Venoco's Chairman and Chief Executive Officer, will also serve as Chairman and Chief Executive Officer of our general partner and will be actively involved in our business. In addition, all of the other executive officers of our general partner also serve as executive officers of Venoco. We, our subsidiaries and our general partner do not have any employees.
We intend to enter into an administrative services agreement with Venoco and our general partner pursuant to which Venoco and its subsidiaries will perform administrative services for us such as accounting, business development, finance, land, legal, engineering, investor relations, management, marketing, information technology, insurance, government regulations, communications, regulatory, environmental and human resources. Venoco and its subsidiaries will be reimbursed for costs they incur in providing such services to us, including reimbursement for a proportionate amount of salary, bonus, incentive compensation and other amounts paid by Venoco and its subsidiaries to persons who perform services for us or on our behalf. Please read "Certain Relationships and Related Party Transactions—Agreements Relating to Our Operations."
Our unitholders will not be entitled to elect our general partner or its directors. Venoco will elect all of the members of the board of directors of our general partner. The board of directors of our general partner will have at least three directors who are independent as defined under the independence standards established by the New York Stock Exchange, or NYSE. For more information
3
about our current directors and executive officers, please read "Management—Directors and Executive Officers."
Summary of Conflicts of Interest and Fiduciary Duties
Our general partner has a legal duty to manage us in a manner beneficial to our unitholders. This legal duty originates in statutes and judicial decisions and is commonly referred to as a fiduciary duty. However, because our general partner is owned by Venoco and its affiliates, the officers and directors of our general partner will also have fiduciary duties to manage our general partner in a manner beneficial to Venoco and its stockholders. As a result of these relationships, conflicts of interest will arise in the future between us and holders of our common and subordinated units, on the one hand, and our general partner and its affiliates, on the other hand.
Our partnership agreement limits the liability of our general partner and reduces the fiduciary duties it owes to us and our unitholders. For example, our partnership agreement provides that Venoco and its affiliates are not restricted from competing with us in circumstances that might otherwise constitute a breach of the general partner's fiduciary duties to us. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of our general partner's fiduciary duties owed to our unitholders. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement and, pursuant to the terms of our partnership agreement, each unitholder consents to various actions contemplated in the partnership agreement and conflicts of interest that might otherwise be considered breaches of fiduciary or other duties under applicable state law.
For a more detailed description of potential conflicts of interest and the fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties."
Other Information
Our principal executive offices are located at 370 17th Street, Suite 3900, Denver, Colorado 80202-1370, and our telephone number is (303) 626-8300. We also maintain regional offices in Carpinteria, California and Houston, Texas.
Formation Transactions and Partnership Structure
We were formed as a Delaware limited partnership on September 25, 2007. As is common with publicly traded partnerships and in order to maximize operational flexibility, we will conduct our operations through, and our operating assets will be owned by, our operating subsidiaries. We will own, directly or indirectly, all of the ownership interests in our operating subsidiaries. The following transactions will occur at or prior to the closing of this offering:
- •
- Venoco will contribute the Partnership Properties to us;
- •
- We will issue to Venoco 6,490,714 common units and 5,339,286 subordinated units, representing an aggregate 55.4% limited partner interest in us, a 2% general partner interest in us, and all of our incentive distribution rights;
- •
- We will issue 9,100,000 common units to the public, representing an aggregate 42.6% limited partner interest in us, and will use the net proceeds from this offering as described in "Use of Proceeds;" and
- •
- We expect to borrow $157.5 million ($117.5 million of which will be secured by marketable securities that we intend to purchase with a portion of the net proceeds of this offering) under our new credit facility, the net proceeds of which will be distributed to Venoco.
4
Organizational Chart and Ownership of Venoco Acquisition Company, L.P.(1)
The following diagram depicts our organization and ownership after giving effect to this offering and the related formation transactions.
Public Common Units | | 42.6 | % |
Venoco, Inc. | | | |
| Common Units | | 30.4 | % |
| Subordinated Units | | 25.0 | % |
| General Partner Interest | | 2.0 | % |
| |
| |
Total | | 100.0 | % |
| |
| |

- (1)
- Assumes that the underwriters' option to purchase an additional 1,365,000 common units is not exercised.
5
The Offering
Common units offered to the public | | 9,100,000 common units. |
| | 10,465,000 common units if the underwriters exercise their option to purchase additional common units in full. |
Units outstanding after this offering | | 15,590,714 common units and 5,339,286 subordinated units, representing 73.0% and 25.0%, respectively, limited partner interests in us. |
Use of proceeds | | We expect to receive net proceeds of approximately $167.5 million from the sale of 9,100,000 common units offered by this prospectus, after deducting underwriting discounts, a structuring fee and $2.0 million of estimated offering expenses. We base our estimate of the offering proceeds on an assumed initial public offering price of $20.00 per common unit. We anticipate using the aggregate net proceeds of this offering to: |
| | • | | purchase $117.5 million of marketable securities, which will be assigned as collateral to secure borrowings under our new credit facility; |
| | • | | distribute $45.0 million in cash to Venoco as reimbursement for capital expenditures incurred by it prior to this offering related to the Partnership Properties, which distribution will be made as partial consideration for the Partnership Properties to be contributed to us at or prior to the closing of this offering; and |
| | • | | fund $5.0 million of working capital. |
| | We also anticipate that we will borrow approximately $157.5 million under our new credit facility at the closing of this offering, and that we will distribute the aggregate amount of the net proceeds from such borrowings to Venoco. |
| | If the underwriters' option to purchase additional common units is exercised in full, we will use the additional net proceeds of $25.4 million to purchase an equivalent amount of marketable securities, which will be assigned as collateral to secure additional borrowings under our new credit facility. The net proceeds of the additional borrowings will be used to redeem from Venoco a number of common units equal to the number of additional common units purchased by the underwriters. |
6
Cash distributions | | We intend to make minimum quarterly distributions of $0.4375 per unit ($1.75 per unit on an annualized basis) to the extent we have sufficient cash available after establishing cash reserves and paying fees and expenses, including reimbursements and other payments to our general partner and its affiliates. Our ability to pay cash distributions at this minimum quarterly distribution rate is subject to various restrictions and other factors described under the caption "Our Cash Distribution Policy and Restrictions on Distributions." |
| | We will pay unitholders a prorated distribution for the first quarter during which we are a publicly traded partnership. Assuming we become a publicly traded partnership before March 31, 2008, we will pay unitholders a prorated distribution for the period from the closing of the offering to and including March 31, 2008. Our first distribution will be paid in the quarter ending June 30, 2008 and will include a prorated amount for the period from the closing of this offering through March 31, 2008. |
| | Our partnership agreement requires us to distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner. We refer to this cash as "available cash," and we define its meaning in our partnership agreement, the form of which is attached as Appendix A, and in the glossary of oil and natural gas terms attached as Appendix B. We intend to retain substantial cash reserves to finance the capital expenditures necessary to maintain our asset base. |
| | Our partnership agreement also requires that we distribute all of our available cash from operating surplus each quarter in the following manner: |
| | • | | first, 98% to the holders of common units and 2% to our general partner, until each common unit has received a minimum quarterly distribution of $0.4375 plus any arrearages from prior quarters; |
| | • | | second, 98% to the holders of subordinated units and 2% to our general partner, until each subordinated unit has received a minimum quarterly distribution of $0.4375; and |
| | • | | third, 98% to all unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.5031. |
7
| | If cash distributions to our unitholders from operating surplus exceed $0.5031 per unit in any quarter, our general partner will receive, in addition to distributions on its 2% general partner interest, increasing percentages, up to 23%, of the cash we distribute in excess of that amount. We refer to these distributions as "incentive distributions." Please read "How We Will Make Cash Distributions." |
| | Our pro forma cash available for distribution for the year ended December 31, 2006 would have been sufficient to pay approximately 88% of the minimum quarterly distribution on our common units, but insufficient to pay any distribution on our subordinated units. Our pro forma cash available for distribution for the twelve months ended September 30, 2007 would have been insufficient to pay the minimum quarterly distribution on any of our common or subordinated units. Please read "Our Cash Distribution Policy and Restrictions on Distributions—Unaudited Pro Forma Cash Available to Pay Distributions." |
| | We believe that, based on the estimates contained in and the assumptions listed under the caption "Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations," we will have sufficient cash available to make cash distributions for the four quarters ending March 31, 2009 at the minimum quarterly distribution rate of $0.4375 per unit ($1.75 per unit on an annualized basis) on all of our common and subordinated units. |
Subordinated units | | Following this offering, Venoco will own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are entitled to receive the minimum quarterly distribution of $0.4375 per unit only after the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. |
Termination of subordination period | | The subordination period generally will end if we have earned and paid from operating surplus at least $1.75 on each outstanding common unit and subordinated unit and the related distributions on our general partner's 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2011. However, if our general partner is removed without cause and the units held by our general partner and its affiliates are not voted in favor of such removal, then the subordination period will end. |
8
| | When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages. |
General partner's right to reset the target distribution levels | | Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (23%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (this amount is referred to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount as in our current target distribution levels. |
| | In connection with resetting the target distribution levels, our general partner will be entitled to receive Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible after one year into an equal number of common units. The number of Class B units to be issued will be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of the reset election divided by (y) the average of the amount of cash distributed per common unit during each of those two quarters. Please read "How We Will Make Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels" |
Issuance of additional units | | We can issue an unlimited number of units, including units that are senior to the common units in right of distributions, liquidation and voting, without the consent of our unitholders. Please read "Units Eligible for Future Sale" and "The Partnership Agreement—Issuance of Additional Securities." |
9
Limited voting rights | | Our general partner will manage and operate us. Your voting rights on matters affecting our business will be more limited than those of a holder of common stock in a corporation. You will have no right to elect our general partner or the directors of our general partner on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. At the closing of this offering, our general partner and its affiliates will own an aggregate of 56.5% of our common and subordinated units. This will give our general partner the practical ability to prevent its involuntary removal. Please read "The Partnership Agreement—Voting Rights." |
Eligible Holders and redemption | | To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands and certain Federal Energy Regulatory Commission requirements, we will require a transferee of our units to fill out a properly completed transfer application certifying that it is an Eligible Holder. In addition, our general partner, acting on our behalf, may at any time require any unitholder to certify that it is an Eligible Holder. An Eligible Holder is a holder of our common units that is both (1) a person or entity qualified to hold an interest in oil and natural gas leases on federal lands and (2) an individual or entity subject to U.S. federal income taxation on our income or an entity not subject to such taxation as long as all of the entity's owners are subject to such taxation. If a transferee or a unitholder, as the case may be, does not properly complete the transfer application or recertification for any reason, the transferee or unitholder will have no right to receive any distributions or allocations of income or loss on its common units or to vote its units on any matter, and we have the right to redeem such units at a price which is equal to the lower of the transferee's or unitholder's purchase price or the then-current market price of such units. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Please read "Description of the Common Units—Transfer of Common Units" and "The Partnership Agreement—Non-Eligible Holders; Redemption." |
Limited call right | | If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then-current market price of the common units. |
10
Estimated ratio of taxable income to distributions | | We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending March 31, 2011, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to our unitholders with respect to that period. For example, if you receive an annual distribution of $1.75 per unit, we estimate that your average allocable federal taxable income per year will be no more than $ per unit. Please read "Material Tax Consequences—Tax Consequences of Common Unit Ownership—Ratio of Taxable Income to Distributions." |
Material tax consequences | | For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material Tax Consequences." |
Exchange listing | | We intend to apply to list our common units on the New York Stock Exchange under the symbol "VAC." |
11
Summary Historical and Pro Forma Financial and Operating Data
Set forth below is summary historical financial data for our accounting predecessor, which we refer to as "Venoco Acquisition Company, L.P. Predecessor," and summary pro forma financial data of Venoco Acquisition Company, L.P., as of the dates and for the periods indicated.
The summary historical financial data presented as of and for the years ended December 31, 2004, 2005 and 2006 are derived from the audited financial statements of Venoco Acquisition Company, L.P. Predecessor included elsewhere in this prospectus. The summary historical financial data presented as of September 30, 2007 and for the nine months ended September 30, 2006 and 2007 are derived from the unaudited financial statements of Venoco Acquisition Company, L.P. Predecessor included elsewhere in this prospectus. The financial statements of Venoco Acquisition Company, L.P. Predecessor reflect the results of operations and financial condition of the Partnership Properties. Due to the factors described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Factors Affecting Comparability of Future Results," our future results of operations will not be comparable to our predecessor's historical results. The summary historical financial data includes the results of acquired properties from their dates of acquisition, including our interest in the Hastings Complex from March 31, 2006 and our interest in the West Montalvo field from May 11, 2007.
The summary pro forma financial data presented for the year ended December 31, 2006 and as of and for the nine months ended September 30, 2007 are derived from the unaudited pro forma financial statements of Venoco Acquisition Company, L.P. included elsewhere in this prospectus. The unaudited pro forma balance sheet data as of September 30, 2007 assume the transactions listed below occurred on September 30, 2007. The unaudited pro forma statement of operations data for the year ended December 31, 2006 and the nine months ended September 30, 2007 assume the transactions listed below occurred on January 1, 2006. We expect to incur incremental general and administrative ("G&A") expenses of approximately $1.0 million per year as a result of being a publicly traded partnership. These expenses are not reflected in our historical financial statements or in our unaudited pro forma financial statements. The unaudited pro forma financial statements of Venoco Acquisition Company, L.P. give pro forma effect to the following transactions:
- •
- the acquisitions of our interests in the Hastings Complex and the onshore portion of the West Montalvo field;
- •
- the contribution of the Partnership Properties to us by Venoco;
- •
- the issuance to Venoco of 6,490,714 common units and 5,339,286 subordinated units, representing an aggregate 55.4% limited partner interest in us, a 2% general partner interest in us, and all of our incentive distribution rights;
- •
- our sale of 9,100,000 common units to the public and the application of the net proceeds of approximately $167.5 million as described in "Use of Proceeds;" and
- •
- our borrowing of approximately $157.5 million ($117.5 million of which will be secured by marketable securities that we intend to purchase with a portion of the net proceeds of this offering) under our new credit facility, the net proceeds of which will be distributed to Venoco.
The summary pro forma financial information should not be considered as indicative of the historical results we would have had if the transactions described above had been completed on the dates indicated or the results we will have after this offering. You should read the following table in conjunction with "—Formation Transactions and Partnership Structure," "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations," the historical carve out financial statements of Venoco Acquisition Company, L.P. Predecessor and the unaudited pro forma financial statements of Venoco Acquisition Company, L.P. included elsewhere in
12
this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.
The following table includes the non-GAAP financial measure of Adjusted EBITDA for the periods presented. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. Please read "—Non-GAAP Financial Measures" for an explanation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities.
| | Venoco Acquisition Company, L.P. Predecessor
| | Pro Forma Venoco Acquisition Company, L.P.
|
---|
| |
| |
| |
| | Nine Months Ended September 30,
| |
| |
|
---|
| | Years Ended December 31,
| |
| | Nine Months Ended September 30, 2007
|
---|
| | Year Ended December 31, 2006
|
---|
| | 2004
| | 2005
| | 2006
| | 2006
| | 2007
|
---|
| | (In thousands)
|
---|
Statement of Operations Data: | | | | | | | | | | | | | | | | | | | | | |
Oil and natural gas revenues | | $ | 27,230 | | $ | 37,879 | | $ | 58,587 | | $ | 42,739 | | $ | 56,056 | | $ | 72,962 | | $ | 59,034 |
Pipeline revenues | | | 6,429 | | | 6,235 | | | 7,595 | | | 5,767 | | | 5,695 | | | 7,595 | | | 5,695 |
| |
| |
| |
| |
| |
| |
| |
|
| Total revenues | | | 33,659 | | | 44,114 | | | 66,182 | | | 48,506 | | | 61,751 | | | 80,557 | | | 64,729 |
Lease operating expenses | | | 12,360 | | | 14,339 | | | 24,031 | | | 17,410 | | | 22,617 | | | 29,647 | | | 23,854 |
Production and property taxes | | | 263 | | | 365 | | | 1,473 | | | 936 | | | 1,249 | | | 1,682 | | | 1,249 |
Transportation expense | | | 567 | | | 707 | | | 970 | | | 695 | | | 684 | | | 970 | | | 684 |
Pipeline operating expense | | | 1,441 | | | 1,617 | | | 2,341 | | | 1,799 | | | 1,536 | | | 2,341 | | | 1,536 |
Depreciation, depletion and amortization | | | 2,299 | | | 2,771 | | | 5,542 | | | 4,293 | | | 7,447 | | | 7,553 | | | 7,947 |
Accretion of abandonment liability | | | 514 | | | 627 | | | 716 | | | 524 | | | 682 | | | 843 | | | 714 |
General and administrative expenses, net of amounts capitalized | | | 1,324 | | | 1,984 | | | 4,048 | | | 2,763 | | | 3,696 | | | 4,048 | | | 3,696 |
Interest expense, net | | | 525 | | | 261 | | | 5,648 | | | 3,881 | | | 5,551 | | | 3,853 | | | 2,890 |
Loss on extinguishment of debt | | | 457 | | | — | | | — | | | — | | | 1,061 | | | — | | | — |
| |
| |
| |
| |
| |
| |
| |
|
| Total financing costs | | | 982 | | | 261 | | | 5,648 | | | 3,881 | | | 6,612 | | | 3,853 | | | 2,890 |
Income tax provision | | | — | | | — | | | 14 | | | 12 | | | 91 | | | 14 | | | 91 |
| |
| |
| |
| |
| |
| |
| |
|
Net income | | $ | 13,909 | | $ | 21,443 | | $ | 21,399 | | $ | 16,193 | | $ | 17,137 | | $ | 29,606 | | $ | 22,068 |
| |
| |
| |
| |
| |
| |
| |
|
Balance Sheet Data (end of period): | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | — | | $ | — | | $ | — | | | | | $ | — | | | | | $ | 5,000 |
Marketable securities | | | — | | | — | | | — | | | | | | — | | | | | | 117,488 |
Total assets | | | 37,897 | | | 42,555 | | | 95,063 | | | | | | 160,788 | | | | | | 282,988 |
Long-term debt | | | — | | | 4,174 | | | 49,965 | | | | | | 83,141 | | | | | | 157,488 |
Owner's/Partners' equity | | | 26,759 | | | 26,993 | | | 26,301 | | | | | | 47,795 | | | | | | 95,648 |
Other Financial Data (unaudited): | | | | | | | | | | | | | | | | | | | | | |
Adjusted EBITDA | | $ | 17,704 | | $ | 25,102 | | $ | 33,319 | | $ | 24,903 | | $ | 31,969 | | $ | 41,869 | | $ | 33,710 |
Cash Flow Data: | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 16,900 | | $ | 24,036 | | $ | 27,009 | | $ | 21,634 | | $ | 26,740 | | | | | | |
| Investing activities | | | (5,687 | ) | | (6,953 | ) | | (48,474 | ) | | (62,163 | ) | | (63,497 | ) | | | | | |
| Financing activities | | | (11,213 | ) | | (17,083 | ) | | 21,465 | | | 40,529 | | | 36,757 | | | | | | |
13
Summary Pro Forma Reserve and Pro Forma Operating Data
The following tables show our estimated pro forma proved oil and natural gas reserves, based on the Reserve Reports, and certain summary unaudited information regarding pro forma production and sales of oil and natural gas with respect to the Partnership Properties. Information in the Reserve Reports includes proved reserves from our interests in the West Montalvo field as of December 31, 2006. You should refer to "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business—Oil and Natural Gas Data" in evaluating the material presented below.
| | December 31, 2006
| |
---|
Estimated pro forma proved reserve data: | | | |
Oil (MMBbl) | | 18.3 | |
Natural gas (Bcf) | | 17.5 | |
| Total (MMBoe) | | 21.2 | |
Proved developed reserves (MMBoe) | | 17.2 | |
Proved undeveloped reserves (MMBoe) | | 4.0 | |
Proved developed reserves as % of total estimated proved reserves | | 81.1 | % |
| | Pro Forma Year Ended December 31, 2006
| | Pro Forma Nine Months Ended September 30, 2007
|
---|
Production and sales data: | | | | | | |
Oil (MBbl) | | | 1,140 | | | 909 |
Natural gas (MMcf) | | | 1,122 | | | 843 |
| Total production (MBoe) | | | 1,327 | | | 1,050 |
Average daily net production (Boe/d) | | | 3,636 | | | 3,845 |
Realized price (in dollars)(1): | | | | | | |
Oil (per Bbl) | | $ | 57.94 | | $ | 58.70 |
Natural gas (per Mcf) | | | 6.15 | | | 6.72 |
Expense per Boe: | | | | | | |
Lease operating expenses | | $ | 22.34 | | $ | 22.72 |
Production and property taxes | | | 1.27 | | | 1.19 |
Transportation expenses | | | 0.73 | | | 0.65 |
Depreciation, depletion and amortization | | | 5.69 | | | 7.57 |
General and administrative expense(2) | | | 3.05 | | | 3.52 |
- (1)
- Amounts shown are based on oil and natural gas sales, net of inventory changes, realized commodity derivative gains (losses), and amortization of derivative premiums divided by sales volumes.
- (2)
- Pro forma general and administrative expense does not include the additional expenses we expect to incur as a result of being a publicly traded partnership. We estimate that these expenses will total approximately $1.0 million per year.
14
Non-GAAP Financial Measures
Adjusted EBITDA
We use Adjusted EBITDA as a supplemental measure of our performance that is not required by, or presented in accordance with, GAAP. We define Adjusted EBITDA as net income before (i) net interest expense, (ii) loss on extinguishment of debt, (iii) income tax provision, (iv) depreciation, depletion and amortization, (v) amortization of derivative premiums, (vi) pre-tax unrealized gains and losses on derivative instruments, (vii) non-cash expenses relating to share-based payments under FAS 123R and (viii) accretion of abandonment liability.
Adjusted EBITDA is used as a supplemental liquidity measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess our ability to:
- •
- generate cash sufficient to pay interest costs and service our debt;
- •
- make cash distributions to our unitholders and general partner; and
- •
- finance capital expenditures.
Adjusted EBITDA is also a financial measure that we expect will be reported to our lenders and used as a gauge for compliance with some of our anticipated financial covenants under our new credit facility.
Adjusted EBITDA is also used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:
- •
- the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
- •
- our operating performance and return on capital as compared to those of other companies in the exploration and production industry, without regard to financing methods or capital structure; and
- •
- the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance, liquidity or ability to service debt obligations. Adjusted EBITDA does not include unrealized gains and losses from hedging, interest expense, income taxes, depreciation, depletion and amortization expense, non-cash expenses related to share based payments under FAS 123R and accretion of abandonment liability. Because we intend to borrow money to finance our operations, interest expense will be a necessary component of our ability to generate gross margins. Because we use capital assets, depreciation, depletion and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income, operating income and net cash provided by operating activities and these measures may vary among companies. Our Adjusted EBITDA may not be comparable to Adjusted EBITDA or EBITDA of another company because other entities may not calculate these measures in the same manner.
15
For more information, please read the historical financial statements of Venoco Acquisition Company, L.P. Predecessor and pro forma financial statements of Venoco Acquisition Company, L.P. and the notes to those statements included elsewhere in this prospectus. The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities on a historical and pro forma basis for the periods presented:
| | Venoco Acquisition Company, L.P. Predecessor
| | Pro Forma Venoco Acquisition Company, L.P.
|
---|
| |
| |
| |
| | Nine Months Ended September 30,
| |
| |
|
---|
| | Years Ended December 31,
| |
| | Nine Months Ended September 30, 2007
|
---|
| | Year Ended December 31, 2006
|
---|
| | 2004
| | 2005
| | 2006
| | 2006
| | 2007
|
---|
| | (In thousands)
|
---|
Net income | | $ | 13,909 | | $ | 21,443 | | $ | 21,399 | | $ | 16,193 | | $ | 17,137 | | $ | 29,606 | | $ | 22,068 |
Interest expense, net | | | 525 | | | 261 | | | 5,648 | | | 3,881 | | | 5,551 | | | 3,853 | | | 2,890 |
Loss on extinguishment of debt | | | 457 | | | — | | | — | | | — | | | 1,061 | | | — | | | — |
| |
| |
| |
| |
| |
| |
| |
|
| Total financing costs | | | 982 | | | 261 | | | 5,648 | | | 3,881 | | | 6,612 | | | 3,853 | | | 2,890 |
Income tax provision | | | — | | | — | | | 14 | | | 12 | | | 91 | | | 14 | | | 91 |
Depreciation, depletion and amortization | | | 2,299 | | | 2,771 | | | 5,542 | | | 4,293 | | | 7,447 | | | 7,553 | | | 7,947 |
Accretion of abandonment liability | | | 514 | | | 627 | | | 716 | | | 524 | | | 682 | | | 843 | | | 714 |
| |
| |
| |
| |
| |
| |
| |
|
Adjusted EBITDA | | | 17,704 | | | 25,102 | | | 33,319 | | | 24,903 | | | 31,969 | | $ | 41,869 | | $ | 33,710 |
| | | | | | | | | | | | | | | | |
| |
|
Less: | | | | | | | | | | | | | | | | | | | | | |
| Cash interest expense, net | | | 424 | | | 106 | | | 4,997 | | | 3,411 | | | 5,139 | | | | | | |
| Income taxes paid | | | — | | | — | | | — | | | — | | | — | | | | | | |
| Change in operating assets and liabilities | | | 380 | | | 960 | | | 1,313 | | | (142 | ) | | 90 | | | | | | |
| |
| |
| |
| |
| |
| | | | | | |
Net cash provided by operating activities | | $ | 16,900 | | $ | 24,036 | | $ | 27,009 | | $ | 21,634 | | $ | 26,740 | | | | | | |
| |
| |
| |
| |
| |
| | | | | | |
16
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 similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.
The risk factors set forth below are not the only risks that may affect our business. Our business could also be affected by additional risks not currently known to us or that we currently deem to be immaterial. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.
Risks Related to Our Business
We may not have sufficient cash flow from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements and other payments to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.
We may not have sufficient available cash from operations each quarter to enable us to pay our unitholders all or part of the minimum quarterly distribution of $0.4375 per unit. 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 that our general partner establishes to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, future debt service requirements and future cash distributions to our unitholders. We plan to reinvest a sufficient amount of our cash flow in acquisitions in order to maintain our production and proved reserves, and we plan to use external financing sources to increase our production and proved reserves.
The amount of cash we actually generate from our operations will depend upon numerous factors related to our business that may be beyond our control, including among other things:
- •
- the amount of oil and natural gas we produce;
- •
- the prices at which we sell our oil and natural gas production;
- •
- our ability to acquire additional oil and natural gas properties at economically attractive prices;
- •
- our ability to effectively hedge commodity prices and the terms of our hedging positions;
- •
- the level of our operating and administrative costs, including the reimbursement of expenses to our general partner and additional expenses we expect to incur as a result of being a publicly traded partnership; and
- •
- the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon.
In addition, the actual amount of cash we will have available for distribution will depend in part on other factors, some of which are beyond our control, including:
- •
- the amount of cash reserves established by our general partner for the proper conduct of our business and for capital expenditures to maintain our production and proved reserves over the long term, which may be substantial;
- •
- the cost to acquire additional oil and natural gas properties;
17
- •
- amounts required to make principal and interest payments on our indebtedness and restrictions on distributions contained in our new credit facility or future debt;
- •
- fluctuations in our working capital needs;
- •
- our ability to borrow additional funds and access the capital markets for additional liquidity; and
- •
- timing and collectibility of receivables.
As a result of these factors, the amount of cash we distribute to our unitholders may fluctuate significantly from quarter to quarter and may be less than the minimum quarterly distribution amount that we expect to distribute. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions."
The amount of cash we have available for distribution to holders of our units depends on our cash flow. On a pro forma basis, we would not have had sufficient cash available for distribution to pay the minimum quarterly distribution on all units for the year ended December 31, 2006 or any distribution on our units for the twelve months ended September 30, 2007.
You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including financial reserves and cash flows from working capital borrowing, 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 for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.
We would not have had enough cash to pay the minimum quarterly distribution on all of our common units and subordinated units on a pro forma basis in 2006. The amount of available cash we need to pay the minimum quarterly distribution for four quarters on all of the units to be outstanding immediately after this offering is approximately $37.4 million. The amount of our pro forma available cash generated during the year ended December 31, 2006 would have been sufficient to pay approximately 88% of the minimum quarterly distribution on our common units, but insufficient to pay any distribution on our subordinated units. Our pro forma cash available for distribution for the twelve months ended September 30, 2007 would have been insufficient to pay the minimum quarterly distribution on any of our common or subordinated units. For a calculation of our ability to make distributions to unitholders based on our pro forma results for 2006, please read "Our Cash Distribution Policy and Restrictions on Distributions."
Our estimate of pro forma cash available for distribution 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 forecasted.
Our estimate of the minimum Adjusted EBITDA necessary for us to pay the minimum quarterly distribution to all of our unitholders as set forth in "Our Cash Distribution Policy and Restrictions on Distributions" for the twelve months ending March 31, 2009 has been prepared by management. The assumptions underlying the forecast 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 forecasted. If we do not achieve the forecasted results or cannot borrow amounts needed, we may not be able to pay all or part of the minimum quarterly distribution on our common units or subordinated units, in which event the market price of our common units may decline materially.
18
A third party has a right to purchase our interest in the Hastings Complex. If this right is exercised and our interest is purchased for a lump-sum cash payment, we would be required to sell a significant portion of our asset base, which represents 33% of our proved reserves and 27% of our pro forma production as of December 31, 2006, and there is no guarantee that we would be able to acquire comparable assets using the proceeds of the transaction in a timely manner to replace the assets we sold.
Denbury Resources, Inc., or Denbury, has an option to acquire our and Venoco's interests in the Hastings Complex in exchange for either a lump-sum cash payment or a right to receive a stream of payments under a volumetric production payment or similar arrangement. If the option is exercised, Venoco will determine whether the consideration we and it receive takes the form of a lump-sum cash payment or a volumetric production payment or similar arrangement. If Venoco elects to receive a lump-sum payment, we would be selling an asset that we expect to provide a significant percentage of our production and cash flow from operations, and there is no guarantee that we would be able to acquire comparable assets using our portion of the payment in a timely manner or at all. If, in those circumstances, we are unable to acquire such assets, or if there is a significant delay in our completion of such an acquisition, our production, cash flow from operations and ability to make distributions to unitholders would decline significantly. If Venoco elects to receive a volumetric production payment or similar arrangement, we would retain commodity price risk with respect to production from the Hastings Complex and would depend on Denbury's performance of its obligations under the payment arrangement for our operating cash flow from this asset. In addition, Venoco and Denbury could agree to amend the option agreement, and that agreement would not require the approval of the conflicts committee of our general partner. Finally, the value of the consideration we and Venoco will receive if Denbury exercises the option will be based on the reserves attributable to our respective interests in the Hastings Complex as determined by an independent reserve engineer. If the determinations of the reserve engineer or then-prevailing commodities prices are unfavorable to us, the value of the consideration we receive may be less than we currently expect. Please read "Business—Properties—Texas" for more information about the Denbury option.
The marketability of our production is dependent upon gathering systems, transportation facilities and processing facilities that we do not control. We rely on one barge to transport production from one of our largest fields. When these facilities or systems, including the barge, are unavailable, our operations can be interrupted and our revenues reduced.
The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems, transportation barges and processing facilities owned by third parties. In general, neither we nor Venoco controls these facilities and our access to them may be limited or denied due to circumstances beyond our control. A significant disruption in the availability of these facilities could adversely impact our ability to deliver to market the oil and natural gas we produce and thereby cause a significant interruption in our operations. In some cases, our ability to deliver to market our oil and natural gas is dependent upon coordination among third parties who own transportation, gathering and processing facilities we use, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt our operations. These are risks for which we generally do not maintain insurance.
We are at particular risk with respect to oil produced at the South Ellwood field, which is one of our largest fields in terms of estimated proved reserves (18.1% of total proved reserves as of December 31, 2006). The oil produced at the field is delivered via a single-hulled barge owned and operated by an unaffiliated third party. This third party is the only company that currently has a permit to deliver oil via barge in the vicinity of the field and, at this time, the barge is the only means available for delivery of oil produced from the field. Our loss of the use of the barge, in the absence of a satisfactory alternative delivery arrangement, would have an adverse effect on our financial condition and results of operations.
19
From time to time, the barge is unavailable due to maintenance and repair requirements. For example, it was out of service for part of August 2006 due to scheduled maintenance. In addition, in October 2006, it was involved in a minor collision with a tugboat and was out of service for repair and inspection for approximately two weeks. In March 2007, it was out of service for inspection for approximately one week. Because there is limited storage capacity for oil produced from the field, production was significantly curtailed at the field during the periods in which the barge was unavailable. In addition, the owner of the refinery to which Venoco has historically delivered oil production from the field informed Venoco in August 2006 that it was unwilling to accept further deliveries from the barge. If the current purchaser of oil production from the field were to make a similar decision, Venoco would have to find a new purchaser and/or enter into an alternative delivery arrangement for the production. Any new delivery or sales arrangement would require time to implement and could require us to accept lower prices for our production and/or incur higher transportation costs. If Venoco is unable, for any sustained period, to maintain or implement acceptable delivery and sales arrangements, it will be required to shut in or curtail production from the field. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of the oil produced from the field, would adversely affect our financial condition and results of operations. We would be similarly affected if any of the other transportation, gathering and processing facilities we use became unavailable or unable to provide services.
Oil and natural gas prices are currently at historically high levels and are very volatile. A sustained decline in these commodity prices will cause a decline in our cash flow from operations, which may cause us to reduce our distributions or cease paying distributions altogether.
The oil and natural gas markets are highly volatile, and we cannot predict future oil and natural gas prices. Oil prices have recently been at historically high levels and natural gas prices have been at high levels over the past several years when compared to prior periods. We expect to hedge a majority of our oil and natural gas production over a three- to five-year period. However, our hedging program will provide only partial protection from declines in oil and nature gas prices and only for periods in which we have hedges in place. A substantial decline in the prices we receive for our oil and natural gas production would have a material adverse effect on us, as our future financial condition, revenues, results of operations, rate of growth, proved reserve estimates, standardized measure value and ability to distribute cash to our unitholders depend primarily upon those prices. Changes in the prices we receive for our oil and natural gas affect, among other things, our ability to finance capital expenditures, make acquisitions, borrow money and satisfy our financial obligations. In addition, declines in prices we receive could reduce the amount of oil and natural gas that we can produce economically and, as a result, could have a material adverse effect on our reserves. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Prices have historically been volatile and are likely to continue to be volatile in the future, especially given current world geopolitical conditions. The prices of oil and natural gas are affected by a variety of other factors that are beyond our control, including:
- •
- changes in global supply and demand for oil and natural gas;
- •
- commodity processing, gathering and transportation availability;
- •
- actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
- •
- domestic and foreign governmental regulations and taxes;
- •
- domestic and foreign political developments, including embargoes, affecting oil-producing activity;
- •
- the level of global oil and natural gas exploration activity and inventories;
20
- •
- the price, availability and consumer acceptance of alternative fuel sources;
- •
- the availability of refining capacity;
- •
- technological advances affecting energy consumption and energy supply;
- •
- weather conditions;
- •
- financial and commercial market uncertainty; and
- •
- worldwide economic conditions.
In the past, the prices of oil and natural gas have been extremely volatile, and we expect this volatility to continue. Please read "Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations—Operations and Revenues—Sensitivity Analysis."
An increase in the differential between NYMEX or other benchmark prices of oil and natural gas and the reference or regional index price used to price our actual oil and natural gas sales could have a material adverse effect on our results of operations and financial condition and our ability to make distributions to our unitholders.
Our oil and natural gas production is priced in the local markets where the production occurs. Pricing can be influenced by local or regional supply and demand factors. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Our California oil typically has a lower API gravity, and a portion has higher sulfur content, than oil sold at the U.S. benchmark oil price, the West Texas Intermediate, or WTI, price, because it requires more complex refining equipment to convert it into high value products. We may be adversely impacted by an increase in the differential on the oil and natural gas we sell relative to the WTI or other benchmarks. The hedging arrangements we expect to enter into will be based on WTI or natural gas index prices, so we may also be subject to basis risk if the differential on the production we sell increases from those benchmarks, unless we have a contract tied to those benchmarks. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in that area compared with other producing areas. For example, the termination in 2006 of the sales arrangement pursuant to which Venoco historically sold oil from the South Ellwood field required Venoco to sell oil on a spot basis for several months at a significantly increased differential than had previously been applicable. In the future, any sales interruptions related to these or other issues could result in similar increases in commodity differentials, which would have a material adverse effect on our results of operations and financial condition and would impair our ability to make cash distributions.
Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantity and present value of our reserves.
The reserve data included in this prospectus represent estimates only. Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates, including estimates based upon assumptions relating to economic factors, such as future commodity prices, production costs, severance and excise taxes and availability of capital, estimates of required capital expenditures and workover and remedial costs, and the assumed effect of governmental regulation. The assumptions underlying our estimates of our proved reserves could prove to be inaccurate, and any significant inaccuracy could materially affect our future estimates of proved 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 estimates of our future net cash flows.
21
At December 31, 2006, 19% of the estimated proved reserves of the Partnership Properties were proved undeveloped and 2% were proved developed non-producing. Estimation of proved undeveloped reserves and proved developed non-producing reserves is almost always based on analogy to existing wells as contrasted with the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Revenues from estimated proved developed non-producing reserves will not be realized until some time in the future, if at all.
You should not assume that the present values referred to in this prospectus represent the current market value of our estimated oil and natural gas reserves. The timing of the production and the expenses related to the development of oil and natural gas properties will affect both the timing of actual future net cash flows from our estimated proved reserves and their present value. In addition, our standardized measure estimates are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Further, the effect of derivative instruments is not reflected in these assumed prices. Also, the use of a 10% discount factor to calculate the standardized measure value may not necessarily represent the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. Any significant variations from the interpretations or assumptions used in our estimates, such as increased or decreased production levels or changes of conditions and information resulting from new or reinterpreted seismic data or otherwise, could cause the estimated quantities and the standardized measure value of our reserves to change materially.
Oil and natural gas exploration, exploitation and development activities may not be successful and could result in a complete loss of a significant investment. If these activities are unsuccessful, our cash available for distribution and our financial condition will be adversely affected.
Exploration, exploitation and development activities are subject to many risks. For example, new wells may not be productive and we may not recover all or any portion of our investment in such wells. Similarly, previously producing wells that are returned to production after a period of being shut in may not produce at levels that justify the expenditures made to bring the wells back on line. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The cost of exploration, exploitation and development activities is subject to numerous uncertainties beyond our control, and cost factors can adversely affect the economics of a project. These expenditures will reduce cash available for distribution to our unitholders. Further, our development activities may be curtailed, delayed or canceled as a result of numerous factors, including:
- •
- title problems;
- •
- problems in delivery of our oil and natural gas to market;
- •
- pressure or irregularities in geological formations;
- •
- equipment failures or accidents;
- •
- shortages of, or delays in obtaining, equipment or qualified personnel;
- •
- adverse weather conditions;
- •
- reductions in oil and natural gas prices;
- •
- compliance with environmental and other governmental requirements; and
22
- •
- costs of, or shortages or delays in the availability of, drilling rigs, equipment and services.
If Venoco does not present us with attractive acquisition opportunities, we may not be able to maintain or increase our asset base, which would adversely affect our cash from operations and our ability to make cash distributions.
Because we do not have any officers or employees, we will rely on Venoco and its affiliates to identify and evaluate for us potential acquisition opportunities. Venoco and its affiliates are not obligated to present us with potential acquisition opportunities. In addition, because Venoco controls our general partner, we will not be able to pursue or consummate any acquisition opportunity unless Venoco causes us to do so. If Venoco and its affiliates do not present us with attractive acquisition opportunities, we may not be able to maintain or increase our asset base, which would adversely affect our cash from operations and our ability to make cash distributions.
If we do not successfully develop and produce our existing reserves or make acquisitions of new reserves on economically acceptable terms, our future growth, ability to maintain current levels of production and reserves and ability to pay or increase distributions will be limited.
Our future oil and natural gas reserves and production, cash flow and ability to make distributions depend on our success in developing and producing our current reserves efficiently and finding or acquiring additional proved reserves economically. If not offset by development, exploitation and acquisition activities, our production and reserves would decline over time due to normal depletion declines, property dispositions and other factors. Based on our Reserve Reports, the estimated production decline rate as of December 31, 2006 was approximately 7.2%. This rate of decline is an estimate based on annual production from the proved developed producing reserves of the Partnership Properties in 2009 when compared to 2008, and actual production declines could be materially higher. Our decline rate may change when we drill additional wells, make acquisitions and under other circumstances.
Our focus on the coastal California and Texas markets reduces the pool of suitable acquisition opportunities. We may be unable to make acquisitions in a variety of situations including those in which:
- •
- Venoco chooses to acquire oil and natural gas properties for itself instead of allowing us to acquire them;
- •
- our conflicts committee is unable to agree with Venoco on a purchase price for Venoco's properties that is attractive to all parties or other purchase terms;
- •
- the terms of Venoco's debt or other agreements make it unwilling or unable to sell assets to us;
- •
- Venoco and its affiliates are unable or unwilling to identify attractive properties or, if identified, are unable to negotiate acceptable purchase contracts;
- •
- we are unable to obtain financing for an acquisition on economically acceptable terms; or
- •
- we are outbid by competitors.
Because the timing and amount of these acquisitions is uncertain, we expect to reserve cash each quarter to finance them, which will reduce our cash available for distribution. 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.
23
The properties we will acquire from Venoco upon the closing of this offering do not include all of the oil and natural gas interests associated with those properties.
As described in "Prospectus Summary—Formation Transactions and Partnership Structure," Venoco will, upon the closing of this offering, contribute to us the Partnership Properties, which consist primarily of working interests in producing oil and natural gas properties. Venoco will not, however, contribute to us all of the oil and natural gas interests associated with those properties. For example, following its contribution of the Partnership Properties to us, Venoco will retain:
- •
- its entire interest in certain currently non-producing zones in the Hastings Complex;
- •
- all its rights to overriding royalty and working interests associated with the Denbury option agreement (please read "Business—Properties—Texas");
- •
- its entire interest in the South Ellwood field, including interests associated with the proposed extension of the field, other than a 23% interest in certain identified wells (also referred to as wellbore assignments) and certain associated rights, including rights to identified proved undeveloped reserves;
- •
- the offshore portion of the West Montalvo Field; and
- •
- the exclusive right to conduct, and all benefits derived from, enhanced oil recovery projects on the Partnership Properties (please read "Business—Properties—Enhanced Oil Recovery").
Venoco's retained interests may have significant exploration, exploitation and development value, and we will not derive any benefit from them. In addition, Venoco's activities with respect to its retained interests could lead to conflicts of interest. For example, Venoco's implementation of an enhanced oil recovery project on one of our properties could interfere with exploitation and development activities we would otherwise pursue. Also, the requirement in the omnibus agreement that the terms of the project agreement be favorable to us does not guarantee that the agreement will be on terms equivalent to those that could be reached with an unaffiliated third party. In addition, if Venoco were to drill or recomplete a well in the South Ellwood field and we elect not to participate in the well, or the well is drilled in an area in which we have no rights, the new well could cause reservoir fluids to migrate towards it and potentially away from our well. The resolution of conflicts of interest of this type may not always be favorable to us.
Our business involves significant operating risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition and results of operations.
Our operations are subject to all the risks normally incident to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells, including:
- •
- well blowouts;
- •
- cratering and explosions;
- •
- pipe failures and ruptures;
- •
- pipeline accidents and failures;
- •
- casing collapses;
- •
- fires;
- •
- mechanical and operational problems that affect production;
- •
- formations with abnormal pressures;
- •
- uncontrollable flows of oil, natural gas, brine or well fluids; and
- •
- releases of contaminants into the environment.
24
For example, in May 2005, Venoco encountered downhole mechanical problems during a routine workover on a well in the South Ellwood field. As a result of the problems, average net production from the well dropped significantly for a period of several months. In addition, Venoco's efforts to restore production at the well required it to delay the implementation of some other projects. We may experience or be affected by similar problems and delays from time to time in the future. Our offshore operations are further subject to a variety of operating risks specific to the marine environment, including a dependence on a limited number of natural gas and water injection wells and electrical transmission lines. Moreover, because we operate in California, we are also susceptible to risks posed by natural disasters such as earthquakes, mudslides, fires and floods.
In addition to lost production and increased costs, these hazards could cause serious injuries, fatalities, contamination or property damage for which we could be held responsible. The potential consequences of these hazards are particularly severe for us because a significant portion of our operations are conducted offshore and in other environmentally sensitive areas, including areas with significant residential populations. We do not maintain insurance in amounts that cover all of the losses to which we may be subject, and insurance may not continue to be available on acceptable terms. The occurrence of an uninsured or underinsured loss could result in significant costs that could have a material adverse effect on our financial condition, results of operations and ability to pay distributions to our unitholders. Finally, maintenance activities undertaken to reduce operational risks can be costly and can require exploration, exploitation and development operations to be curtailed while those activities are being completed.
We are subject to complex laws and regulations, including environmental laws and regulations, which can adversely affect the cost, manner and feasibility of doing business.
Our operations and facilities are subject to extensive federal, state and local laws and regulations relating to exploration for, and the exploitation, development, production and transportation of, oil and natural gas, as well as environmental and safety matters. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, may adversely affect our business, results of operations and financial condition. Laws and regulations applicable to us include those relating to:
- •
- land use restrictions, which are particularly strict along the coast of southern California where many of our operations are located;
- •
- drilling bonds and other financial responsibility requirements;
- •
- spacing and density of wells;
- •
- limits on oil or natural gas production;
- •
- emissions into the air (including emissions from ships in the Santa Barbara channel) and discharges into water;
- •
- unitization and pooling of properties;
- •
- habitat and endangered species protection, reclamation and remediation;
- •
- the containment and disposal of hazardous substances, oil field waste and other waste materials;
- •
- the use of underground and aboveground storage tanks;
- •
- transportation permits;
- •
- the use of underground injection wells, which affects the disposal of fluids, including produced water, from our wells;
- •
- safety precautions;
25
- •
- the prevention of oil spills;
- •
- the closure of production facilities;
- •
- operational reporting;
- •
- prohibitions on manipulation of natural gas markets; and
- •
- taxation and royalties.
Under these laws and regulations, we could be liable for:
- •
- personal injuries;
- •
- property and natural resource damages;
- •
- emissions, releases or discharges of hazardous materials;
- •
- well reclamation costs;
- •
- oil spill clean-up costs;
- •
- other remediation and clean-up costs;
- •
- plugging and abandonment costs, which may be particularly high in the case of offshore facilities;
- •
- governmental sanctions, such as fines and penalties; and
- •
- other environmental damages.
Any noncompliance with these laws and regulations could subject us to material administrative, civil or criminal penalties or other liabilities. Venoco is a defendant in a series of lawsuits alleging, among other things, that air, soil and water contamination from the oil and natural gas facility at the Beverly Hills West field caused the plaintiffs to develop cancer or other diseases or to sustain related injuries. Venoco has informed us that it cannot predict the cost of defense and indemnity obligations at the present time. Venoco has agreed to indemnify us for any liabilities and expenses resulting from the currently pending lawsuits. However, Venoco will not be obligated to indemnify us for any liabilities or expenses associated with the operation of the field following its contribution to us. If similar lawsuits are filed in the future based on damages suffered during our period of operation, we would be responsible for any resulting liabilities and expenses. Please read "Certain Relationships and Related Party Transactions—Agreements Relating to Our Operations—Omnibus Agreement." In addition, compliance with applicable laws and regulations could require us to delay, curtail or terminate existing or planned operations.
Some environmental laws and regulations impose strict liability. Strict liability means that in some situations we could be exposed to liability for clean-up costs and other damages as a result of conduct that was lawful at the time it occurred or for the conduct of prior operators of properties we have acquired or other third parties. In addition, we may be required to make large and unanticipated capital expenditures to comply with applicable laws and regulations, for example by installing and maintaining pollution control devices. Similarly, our plugging and abandonment obligations will be substantial and may be more than our estimates. Compliance costs are relatively high for us because many of our properties are located offshore California and in other environmentally sensitive areas and because California environmental laws and regulations are generally very strict. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters, but such costs may be material. In addition, our operations could be adversely affected by federal and state laws that require environmental impact studies to be conducted before governmental authorities can take certain actions, including in some cases the issuance of permits to us. We may not be able to recover any or all of our environmental costs from insurance.
26
We could also be adversely affected by existing or future tax laws and regulations. For example, proposals have been made to amend federal and California law to impose "windfall profits" taxes or other types of additional taxes on oil companies. If any of these proposals become law, our costs would increase, possibly materially.
Our development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could adversely affect our ability to replace our production and reserves.
The oil and natural gas industry is capital intensive. We expect to make substantial capital expenditures to develop, exploit and acquire oil and natural gas reserves. These expenditures will reduce our cash available for distribution. We intend to finance our future capital expenditures with cash flow from operations, borrowings under our new credit facility that we expect to enter into at the closing of this offering and the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. Our cash flow from operations and access to capital is subject to a number of variables, including:
- •
- the estimated quantities of our oil and natural gas reserves;
- •
- the amount of oil and natural gas we produce from existing wells;
- •
- the prices at which we sell our production; and
- •
- our ability to acquire, locate and produce new reserves.
If our cash flow from operations or the borrowing base under our new credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may not be able to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our new credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which could lead to a possible decline in our reserves and production. This could adversely affect our business, results of operations, financial condition and ability to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.
Our regulated pipelines are subject to federal, state, and/or local regulation, which can include rate regulation, regulation of terms and conditions of transportation service, and requirements to provide non-discriminatory access. Existing and future regulation of our pipelines, including the outcome of pending policy proceedings on appropriate treatment of tax allowances included in regulated rates, and appropriate return on equity, may reduce our transportation revenues, affect our ability to include certain costs in regulated rates, increase our cost of operations and thus affect our distributions.
Our interstate oil pipelines are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Interstate Commerce Act, or ICA. The ICA requires that tariff rates for petroleum pipelines be just and reasonable and non-discriminatory. Shippers may protest the pipeline tariff filings of our interstate common carrier oil pipelines that are subject to FERC regulation under the ICA, and FERC may investigate new or changed tariff rates. Further, other than for rates set under market-based rate authority and for rates that remain grandfathered under the Energy Policy Act 1992 (and thus subject to certain limitations on complaints and refund obligations), FERC may order refunds of amounts collected under rates that were in excess of a just and reasonable level when taking into consideration the pipeline system's cost of service. In addition, shippers may challenge the lawfulness of tariff rates that have become final and effective. FERC may also investigate such rates absent shipper
27
complaint. FERC's ratemaking methodologies may limit our ability to set rates based on our true costs or may delay the effectiveness of rates that reflect increased costs.
FERC has pending a proceeding regarding the methodology to be used for determining natural gas and oil pipeline equity returns to be included in cost-of-service based rates and regarding the appropriate composition of proxy groups to be used in the methodology. The ultimate outcome of this or other proceedings is not certain and may result in new policies being established at FERC that would not allow the full use of distributions to unitholders by pipeline publicly traded partnerships in any proxy group comparisons used to determine return on equity in future rate proceedings, or which might limit the amount of income tax allowance permitted to be recovered in regulated rates. We cannot assure that any such policy developments will not adversely affect our FERC regulated pipelines' abilities to achieve a reasonable level of return or impose limits on their abilities to include a full income tax allowance in cost of service.
Our oil and natural gas pipelines are also subject to the pipeline safety regulations of the federal Department of Transportation. For more information on pipeline safety matters, please read "Business—Safety and Maintenance."
A change in the jurisdictional characterization of the Union Island Pipeline could result in regulation of the Union Island Pipeline by the CPUC, which could cause our revenues to decline and operating expenses to increase.
Although the California Public Utilities Commission, or CPUC, has not issued any determination regarding the jurisdictional status of the Union Island Pipeline that we own, we believe that the Union Island Pipeline meets the test applied by the CPUC for determining whether a pipeline is not subject to CPUC regulation. If the CPUC were to assert jurisdiction over the Union Island Pipeline, our revenues might decline and our operating expenses might increase.
Our pipelines located on the Outer Continental Shelf, or OCS, are subject to regulation by the Minerals Management Service, or MMS, under the Outer Continental Shelf Lands Act, or OCSLA, which requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. The MMS has a pending rulemaking proceeding that would establish a process for a shipper transporting oil or natural gas production from OCS leases to follow if it believes it has been denied open and nondiscriminatory access to OCS pipelines. The MMS proposal includes a provision for civil penalties of up to $10,000 per day for violations of the open and nondiscriminatory access requires of the OCSLA. We have no way of knowing what rules the MMS will ultimately adopt regarding access to OCS transportation and what effect, if any, those rules will have on our OCS pipeline operations, revenues, and profitability.
Properties that we buy may not produce as projected and we may be unable to determine reserve potential or identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution.
Any future acquisition that we pursue will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher-valued properties and are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. 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 potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment, are not necessarily observable even when an inspection is undertaken. Any unidentified
28
problems could result in material liabilities and costs that negatively impact our financial condition and results of operations and our ability to make cash distributions to our unitholders.
Additional potential risks related to acquisitions include, among other things:
- •
- incorrect assumptions regarding future prices of oil and natural gas or the future operating or development costs of properties acquired;
- •
- incorrect estimates of the oil and natural gas reserves attributable to a property we acquire;
- •
- an inability to integrate successfully the businesses we acquire;
- •
- the assumption of unknown or improperly estimated liabilities;
- •
- limitations on rights to indemnity from the seller;
- •
- the diversion of management's attention from other business concerns; and
- •
- losses of key employees at the acquired businesses.
If we consummate any future acquisitions, our capitalization and results of operations may change significantly.
Our new credit facility will limit our ability to make distributions to our unitholders and may limit our flexibility in pursuing business opportunities. Debt service obligations will reduce the amount of funds available for other purposes, including distributions to unitholders.
We plan to enter into a credit facility in connection with the closing of this offering. Borrowings under our new credit facility, and other indebtedness we may incur in the future, could have important consequences to us, including the following:
- •
- our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be limited by the terms or amount of our then-outstanding indebtedness;
- •
- covenants contained in our new credit facility and other debt arrangements may require us to meet financial tests that will affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities, and in determining the amount of distributions to unitholders;
- •
- we will 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 will 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 cash flows from operations 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.
29
Increases in interest rates could adversely impact our debt service obligations, our unit price and our ability to issue additional equity and incur debt in the future.
We expect that amounts borrowed under our new credit facility we will enter at the closing of this offering will bear interest at variable rates. Accordingly, an increase in market interest rates would cause an increase in our debt service obligations. In addition, an increase in interest rates could adversely affect the market price of our units. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or incur debt in the future.
Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay distributions to our unitholders.
To achieve more predictable cash flow and to reduce our exposure to fluctuations in the prices of oil and natural gas, we expect to enter into hedging arrangements for a significant portion of our oil and natural gas production. If we experience a sustained material interruption in our production or if we are unable to perform our drilling activity as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Hedging arrangements also limit our ability to benefit from future increases in oil and natural gas prices that may occur. In addition, if the counterparty to any derivative transaction cannot or will not perform under the instrument, we will not realize the benefit of the hedge.
Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes.
We expect to hedge a majority of our oil and natural gas production over a three- to five-year period. As our hedges expire, more of our future production will be sold at market prices unless we enter into further hedging transactions. Our hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current prices. Accordingly, our hedging strategy may not protect us from declines in prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodities price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared to the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.
Competition in the oil and natural gas industry is intense and may adversely affect our results of operations.
We operate in a competitive environment for acquiring properties, marketing oil and natural gas, integrating new technologies and employing skilled personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be willing and able to pay more for oil and natural gas properties than our financial resources permit, and may be able to define, evaluate, bid for and purchase a greater number of properties. Our competitors may also enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the
30
future with respect to acquiring prospective reserves, developing reserves, marketing our production, attracting and retaining qualified personnel, implementing new technologies and raising additional capital.
We do not have any employees and rely solely on officers of our general partner and employees of Venoco. Failure of such officers and employees 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.
None of the officers of our general partner are employees of our general partner, and we do not have any employees. We intend to enter into an administrative services agreement with Venoco and our general partner pursuant to which Venoco will perform administrative services for us, such as accounting, corporate development, finance, land, legal and engineering. Venoco will have substantial discretion in determining which third-party expenses to incur on our behalf. Venoco conducts business and activities of its own in which we have no economic interest. Accordingly, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and its affiliates. If the officers of our general partner and the employees of Venoco and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our unitholders may be reduced.
Changes in the financial condition of any of our large oil and natural gas purchasers could make it difficult to collect amounts due from those purchasers.
For the year ended December 31, 2006, approximately 90% of our oil and natural gas revenues were generated from sales to four purchasers: ConocoPhillips (38%), Shell Trading (US) Co. (10%), GulfMark Energy (28%), and Tesoro Refining and Marketing Company (14%). No other purchaser represented 10% or more of our revenues. A material adverse change in the financial condition of any of our largest purchasers could adversely impact our future revenues and our ability to collect current accounts receivable from such purchasers.
We may be required to write down the carrying value of our properties and a reduction in our asset values could adversely affect the market price of our units.
We may be required under full cost accounting rules to write down the carrying value of our properties when oil and natural gas prices decrease or when we have substantial downward adjustments of our estimated proved reserves, increases in our estimates of development costs or deterioration in our exploitation and development results. We use the full cost method of accounting for oil and natural gas exploitation, development and exploration activities. Under full cost accounting rules, we perform a "ceiling test." This test is an impairment test and generally establishes a maximum, or "ceiling," of the book value of our oil and natural gas properties that is equal to the expected after-tax present value of the future net cash flows from estimated proved reserves, including the effect of cash flow hedges, calculated using prevailing prices on the last day of the relevant period. If the net book value of our properties (reduced by any related net deferred income tax liability) exceeds the ceiling, we write down the book value of the properties. Depending on the magnitude of any future impairments, a ceiling test write down could significantly reduce our income or produce a loss. Ceiling test computations use commodity prices prevailing on the last day of the relevant period, making it impossible to predict the timing and magnitude of any future write downs. To the extent our finding and development costs increase, we will become more susceptible to ceiling test write downs in low price environments.
31
Risks Inherent in an Investment in Us
Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with us and have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of our common unitholders. Our partnership agreement limits the circumstances under which our common unitholders may make a claim relating to conflicts of interest and the remedies available to holders of units in that event.
Following the offering, Venoco will own and control our general partner and will own 41.6% of our common units and 100% of our subordinated units. The directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Venoco. Furthermore, certain directors and officers of our general partner will be directors or officers of Venoco. Conflicts of interest will arise between Venoco and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. Conflicts will arise in a number of situations, including the following:
- •
- Venoco will compete with us, including for future acquisition opportunities, and is under no obligation to offer properties to us. We will be able to compete for acquisitions and other opportunities only to the extent Venoco causes us to do so.
- •
- We will enter into agreements with Venoco, our general partner and others at the closing of this offering pursuant to which we will have ongoing obligations to Venoco. Pursuant to these agreements, we will, among other things, reimburse Venoco for the cost of certain services its employees provide to us. Please read "Certain Relationships and Related Party Transactions" for a description of these agreements. In addition, our partnership agreement does not prohibit our general partner from causing us to enter into additional agreements with Venoco and its affiliates. Furthermore, our general partner, and ultimately Venoco, controls the enforcement of obligations owed to us by it and its affiliates.
- •
- Venoco determines the manner in which its personnel and operational resources are utilized and is not prohibited from favoring other properties it operates over our properties, so long as it conducts itself in accordance with the operating standards set forth in the relevant operating agreement.
- •
- The officers of our general partner who will provide services to us will also devote time to Venoco. Accordingly, those officers will not devote their full attention to our business.
- •
- Our general partner determines the amount and timing of expenses, asset purchases and sales, capital expenditures, borrowings, repayments of indebtedness, issuances of additional partnership securities and cash reserves, each of which can affect the amount of cash that is available for distribution to our unitholders. In addition, our general partner may cause us to borrow funds in order to make cash distributions. Each of these matters may involve a conflict of interest in that it can affect (i) when and whether the subordination period terminates, (ii) the extent to which the general partner is entitled to receive distributions with respect to its incentive distribution rights and (iii) when and whether the general partner can reset the target distribution levels for its incentive distribution rights.
- •
- Our general partner intends to limit its liability regarding our contractual obligations and expects to make any of our debt or other contractual obligations nonrecourse to it. This may make it more difficult for us to obtain needed financing.
- •
- Our general partner may exercise its rights to call and purchase all of our common units if at any time it and its affiliates own more than 80% of the outstanding common units.
- •
- Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
32
In resolving these conflicts, our general partner may favor its own interests and the interests of Venoco and its affiliates over the interests of our unitholders because the partnership agreement limits its fiduciary duties to us and our unitholders. In particular, the partnership agreement:
- •
- generally provides that an affiliated transaction or the resolution of a conflict of interest will not constitute a breach of our general partner's fiduciary duties if it is (i) approved by the conflicts committee of the board of directors of our general partner, (ii) approved by our unitholders, (iii) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (iv) otherwise fair and reasonable to us as determined by our general partner in good faith. 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; and
- •
- permits our general partner to make a number of decisions in its individual capacity rather than in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. Examples include decisions with respect to its right to reset the target distribution levels of its incentive distribution rights, its limited call right and the exercise of its voting and registration rights.
Please read "Certain Relationships and Related Party Transactions" and "Conflicts of Interest and Fiduciary Duties."
Cost reimbursements owed to our general partner and its affiliates for services provided may be substantial and will reduce the amount of cash available for distribution to our unitholders.
Pursuant to an administrative services agreement we will enter into with Venoco, our general partner and others at the closing of this offering, Venoco will receive reimbursement for the provision of various general and administrative services for our benefit. In addition, we will enter into an operating agreement with Venoco pursuant to which a Venoco subsidiary will be the operator of all of the wells for which we have the right to appoint an operator. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. Please read "Certain Relationships and Related Party Transactions—Agreements Relating to Our Operations." In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments would reduce the amount of cash otherwise available for distribution to our unitholders.
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights. This may result in lower distributions to holders of our common units in certain situations.
Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (23%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.
33
In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by the average of the amount of cash distributed per common unit during each of these two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us in the same amounts and with the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued the Class B units to our general partner in connection with the reset. Please read "How We Will Make Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."
Common unitholders will have limited voting rights and will not be entitled to elect our general partner or its directors.
The voting rights of holders of our common units will be more limited than the voting rights of stockholders in a corporation. Unitholders will have no right to elect our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner will be chosen by Venoco. Unitholders' voting rights are further restricted by a provision of the partnership agreement that eliminates the voting rights of any person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings.
In addition, the common unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units at the closing of this offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding units voting together as a single class is required to remove the general partner. Following the closing of this offering, our general partner and Venoco will own 56.5% of our aggregate outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Poor business management would not ordinarily constitute cause, so the removal of the general partner because of the unitholder's dissatisfaction with our general partner's performance in managing our partnership would most likely result in the termination of the subordination period and conversion of all subordinated units to common units.
34
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 in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Venoco or its affiliates to transfer all or a portion of their respective ownership interests in our general partner to or pledge such ownership interests for the benefit of a third party. In the event of a transfer or foreclosure by a secured lender, the new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.
Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the closing of this offering and assuming no exercise of the underwriters' option to purchase additional common units, Venoco will own approximately 41.6% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units and that all of the subordinated units are converted into common units, Venoco will own approximately 56.5% of our aggregate outstanding common and subordinated units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."
We may issue additional units without your approval, which would dilute your existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. 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;
- •
- because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
- •
- 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.
Venoco may sell common units in the public markets, which sales could have an adverse impact on the trading price of the common units.
Following this offering, Venoco will hold an aggregate of 6,490,714 common units and 5,339,286 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of common units in the public markets could have an adverse impact on the price of the units on any trading market that may develop.
35
We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions, and covenants in our new credit facility or other debt agreements may restrict our ability to make distributions.
Our partnership agreement allows us to borrow to make distributions. We may make short term borrowings under our new credit facility or other debt agreements, which we refer to as working capital borrowings, to make distributions. The repayment obligations we would incur in connection with these borrowings would reduce the amount of cash available in subsequent periods for distribution to unitholders.
The terms of our new credit facility or other debt agreements may restrict our ability to pay distributions in certain circumstances, for example if we were unable to satisfy the financial and other covenants of the facility.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production.
Our partnership agreement provides that we will distribute all of our available cash each quarter. As a result, we will be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money, as well as the costs of such financings, including:
- •
- General economic and market conditions, including interest rates, prevailing at the time we desire to issue securities or borrow funds;
- •
- conditions in the oil and natural gas industry;
- •
- the market price of, and demand for, our common units;
- •
- our results of operations and financial condition; and
- •
- prices for oil and natural gas.
If we distribute cash from capital surplus, our minimum quarterly distribution rate will be reduced proportionately, and the distribution thresholds for determining payments on incentive distribution rights will be proportionately decreased.
Our cash distributions will be characterized as coming from either operating surplus or capital surplus. Operating surplus is defined in our partnership agreement, and generally means amounts we receive from operating sources, such as sales of our oil and natural gas production, less operating expenditures, such as production costs and taxes, and less estimated average capital expenditures, which are generally amounts we estimate we will need to spend in the future to maintain our production and reserves over the long term. Capital surplus is defined in our partnership agreement and generally means amounts we receive from non-operating sources such as sales of properties and issuances of debt and equity securities. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98% to our unitholders and two percent to our general partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner. For a complete description of operating surplus and capital surplus, please read "How We Will Make Cash Distributions."
Our partnership agreement allows us to add to operating surplus up to two times the amount of our most recent minimum quarterly distribution. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.
36
You will experience immediate and substantial dilution of $15.52 in net tangible book value per common unit.
The initial public offering price of $20.00 per unit exceeds our pro forma net tangible book value of $4.48 per unit. Therefore, you will incur immediate and substantial dilution of $15.52 per common unit. This dilution occurs because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."
Your liability 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 operate or may operate in the future. You could be liable for any and all of our obligations as if you were a general partner if:
- •
- 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
- •
- your 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.
For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."
Unitholders may have liability for the repayment of distributions that were wrongfully distributed to them.
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 our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the 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 distributed amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
We will incur increased costs as a result of being a publicly traded partnership.
We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses that are not reflected in our historical financial statements. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules subsequently implemented by the SEC and the NYSE, have required changes in corporate governance practices of publicly traded companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly. For example, as a result of us becoming a publicly traded partnership, our general partner will be required to have at least three independent directors, to create specified board committees and to adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur costs associated with our obligation to file reports under the Securities Exchange Act of 1934 and related rules and our need to obtain
37
director and officer liability insurance. Limits in the insurance we obtain may make it difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as officers. We have included approximately $1.0 million of estimated incremental costs per year, some of which may be allocated to us by Venoco, associated with being an independent publicly traded partnership for purposes of our financial forecast included elsewhere in this prospectus; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
If we do not develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.
Unitholders may have limited liquidity for their units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.
Prior to the offering, there has been no public market for the units. After the offering, there will be 9,100,000 publicly traded units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. A lack of liquidity may prevent you from being able to resell your units at or above the initial public offering price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the units and limit the number of investors who are able to buy the units.
In addition, trading markets may experience periods of volatility, which could result in highly variable and unpredictable pricing of securities. The market price of our common units could change in ways that may or may not be related to our business, our industry or our operating performance and financial condition.
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 certain U.S. laws with respect to the ownership of interests in oil and natural gas leases on federal lands and to comply with certain FERC requirements, we require that investors who own our common and subordinated units be Eligible Holders. As used in our partnership agreement, an Eligible Holder means both (1) a person or entity qualified to hold an interest in oil and natural gas leases on federal lands and (2) a person or entity subject to U.S. federal income taxation on our income or entities not subject to such taxation as long as all of the entity's owners are subject to such taxation.
In either case, unitholders that are not Eligible Holders will not receive distributions or allocations of income and loss on their units and they run the risk of having their units redeemed by us at the lower of their purchase price cost or 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. Please read "Description of the Common Units—Transfer of Common Units" and "The Partnership Agreement—Non-Eligible Holders; Redemption."
38
Tax Risks to Common Unitholders
In addition to reading the following risk factors, you should read "Material Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.
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 IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.
The anticipated after-tax economic benefit of an investment in our 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 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 are so treated, 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 personally 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 you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you 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, at the federal level, 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.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, beginning in 2008, we will be required to pay Texas franchise tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of such a tax on us by Texas and, if applicable, by any other state will substantially reduce the cash available for distribution to you.
It is possible that these efforts could result in changes to the existing U.S. or state tax laws that affect publicly traded partnerships, including 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 common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
39
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common 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 common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration 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. Please read "Material Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the costs of any IRS contest will reduce our cash available for distribution to you.
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 conclusions of our counsel expressed in this prospectus or 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 some or 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 result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our common unitholders and our general partner.
You will be required to pay taxes on your share of our income even if you 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, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the common units you sell will, in effect, become taxable income to you if you sell such common units at a price greater than your tax basis in those
40
common units, even if the price you receive is less than your 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 depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read "Material Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss" for a further discussion of the foregoing.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), 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 imposed at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
We will treat each purchaser of 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 adopt 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 you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Tax Consequences—Tax Consequences of Common Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we will adopt.
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. Vinson & Elkins L.L.P. 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 borrowing their units.
41
We will 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 challenge this treatment, which could adversely affect the value of the 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 our general partner. 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, under our valuation methods, 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 valuation 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.
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 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. 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 our unitholders would receive two Schedule K-1's) 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 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. Please read "Material Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.
As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.
In addition to federal income taxes, you may become 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 or acquire property now or in the future, even if you do not live in any of those jurisdictions. You 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. Further, you may be subject to penalties for failure to comply with those requirements. We will initially conduct business and own assets in Texas and California. California imposes a personal income tax on individuals and Texas and California impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may conduct business or own assets in additional states that impose a personal income tax or an entity level tax. It is the responsibility of each common unitholder to file all U.S. federal, foreign, state and local tax returns applicable to you in your particular circumstances. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.
42
USE OF PROCEEDS
We expect to receive net proceeds of approximately $167.5 million from the sale of 9,100,000 common units offered by this prospectus, after deducting underwriting discounts, a structuring fee of $ and estimated offering expenses of $ . We based our estimate of the offering proceeds on an assumed initial public offering price of $20.00 per common unit and we assume no exercise of the underwriters' option to purchase additional common units. We anticipate using the aggregate net proceeds of this offering to:
- •
- purchase $117.5 million of marketable securities, which will be assigned as collateral to secure borrowings under our new credit facility;
- •
- distribute $45.0 million in cash to Venoco as reimbursement for capital expenditures incurred by it prior to this offering related to the Partnership Properties, which distribution will be made as partial consideration for the Partnership Properties that will be contributed to us at or prior to the closing of this offering; and
- •
- fund $5.0 million in working capital.
We also anticipate that we will borrow approximately $157.5 million under our new credit facility at the closing of this offering, and that we will distribute the aggregate amount of the net proceeds from such borrowings to Venoco.
If the underwriters' option to purchase additional common units is exercised in full, we will use the additional net proceeds of $25.4 million to purchase an equivalent amount of marketable securities, which will be assigned as collateral to secure the additional borrowings under our new credit facility. The net proceeds of the additional borrowings will be used to redeem from Venoco a number of common units equal to the number of additional common units purchased by the underwriters.
Certain affiliates of Lehman Brothers Inc., Citigroup Global Markets Inc. and UBS Securities LLC serve as agents, arrangers and lenders under Venoco's revolving credit agreement and term loan agreement and expect to be lenders under our new credit facility. Venoco has informed us that it intends to use a portion of the distribution we will make to it in connection with the closing of this offering to reduce amounts outstanding under its revolving credit facility. Please read "Underwriting."
43
CAPITALIZATION
The following table shows:
- •
- the historical capitalization of our predecessor as of September 30, 2007;
- •
- our pro forma cash, cash equivalents and marketable securities and our capitalization as of September 30, 2007, adjusted to reflect this offering, the application of the net proceeds from this offering as described under "Use of Proceeds" and the formation transactions described under "Prospectus Summary—Formation Transactions and Partnership Structure" as if each of those transactions had occurred on that date.
We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations."
| | As of September 30, 2007
| |
---|
| | Historical
| | Pro Forma(1)
| |
---|
| | (In thousands)
| |
---|
Cash and cash equivalents | | $ | — | | $ | 5,000 | |
| |
| |
| |
Marketable securities | | $ | — | | $ | 117,488 | |
| |
| |
| |
Total long-term debt(2)(3) | | $ | 83,141 | | $ | 157,488 | |
Owner's/Partners' equity: | | | | | | | |
| Net parent equity | | | 47,795 | | | — | |
| Common units—Public | | | — | | | 167,488 | |
| Common units—Venoco | | | — | | | (38,043 | ) |
| Subordinated units—Venoco | | | — | | | (31,294 | ) |
| General partner interest | | | — | | | (2,503 | ) |
| |
| |
| |
| | Total Owner's/Partners' equity | | | 47,795 | | | 95,648 | |
| |
| |
| |
Total capitalization | | $ | 130,936 | | $ | 253,136 | |
| |
| |
| |
- (1)
- Assumes an initial public offering price of our common units of $20.00 per unit and reflects partner capital of common unitholders from the net proceeds of this offering of approximately $167.5 million after deducting underwriting discounts, a structuring fee and $2.0 million of estimated offering expenses, and the application of the proceeds as described in "Use of Proceeds." A $1.00 increase or decrease in the assumed initial public offering price per common unit would increase or decrease, respectively, the net proceeds by approximately $8.5 million. The pro forma information discussed above is illustrative only and following completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.
- (2)
- Historical amount reflects an allocation of Venoco's historical debt.
- (3)
- Pro forma amount represents expected borrowings under our new credit facility we expect to enter into at the closing of this offering.
44
DILUTION
Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2007, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters' option to purchase additional common units is not exercised, our net tangible book value was $95.6 million, or $4.48 per common unit. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:
Initial public offering price per common unit | | | | | $ | 20.00 |
Net tangible book value per unit before the offering(1) | | $ | 3.90 | | | |
Increase in net tangible book value per common unit attributable to purchasers in the offering | | | 0.58 | | | |
| |
| | | |
Less: Pro forma net tangible book value per unit after the offering(2) | | | | | | 4.48 |
| | | | |
|
Immediate dilution in net tangible book value per common unit to new investors | | | | | $ | 15.52 |
| | | | |
|
- (1)
- Determined by dividing the number of units and general partner equivalent units (6,490,714 common units, 5,339,286 subordinated units and 427,143 general partner equivalent units) to be issued to Venoco for its contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities.
- (2)
- Determined by dividing the total number of units and general partner equivalent units to be outstanding after the offering (15,590,714 common units, 5,339,286 subordinated units and 427,143 general partner equivalent units) into our pro forma net tangible book value after giving effect to the application of the expected net proceeds of the offering.
The following table sets forth the number of units that we will issue and the total consideration contributed to us by Venoco and by the purchasers of common units in this offering upon completion of the transactions contemplated by this prospectus:
| | Units Acquired
| | Total Consideration
| |
---|
| | Number
| | Percent
| | Amount
| | Percent
| |
---|
| |
| |
| | (In thousands)
| |
---|
General partner and its affiliates(1)(2) | | 12,257,143 | | 57.4 | % | $ | 2,795 | | 1.5 | % |
New investors | | 9,100,000 | | 42.6 | % | | 182,000 | | 98.5 | % |
| |
| |
| |
| |
| |
| Total | | 21,357,143 | | 100.0 | % | $ | 184,795 | | 100.0 | % |
| |
| |
| |
| |
| |
- (1)
- Upon completion of the transactions contemplated by this prospectus, Venoco will own 6,490,714 common units, 5,339,286 subordinated units and a 2% general partner interest represented by 427,143 general partner equivalent units.
- (2)
- The assets contributed by affiliates of Venoco were recorded at historical cost in accordance with GAAP. The total consideration provided by affiliates of Venoco, as of September 30, 2007, is equal to the net tangible book value of such assets.
45
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS
You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read "—Assumptions and Considerations" below. In addition, you should read "Forward-Looking Statements" and "Risk Factors" for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.
For additional information regarding our historical and pro forma operating results, you should refer to our historical financial statements for the years ended December 31, 2004, 2005 and 2006 and for the nine months ended September 30, 2006 and 2007, and our pro forma financial statements for the year ended December 31, 2006, and the nine months ended September 30, 2007, included elsewhere in this prospectus.
General
Our Cash Distribution Policy. Our partnership agreement requires us to distribute all of our available cash quarterly. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax. The amount of available cash that we have will be determined by the board of directors of our general partner for each calendar quarter after the closing of this offering and will be based upon recommendations from our management. It is the board's current policy that we will pay a minimum quarterly distribution of $0.4375 per unit for each complete quarter, and that we should increase our level of quarterly cash distributions per unit only when, in the board's judgment, it believes that (i) we have sufficient cash reserves and liquidity for the conduct of our business, including to fund the level of estimated maintenance capital expenditures required to maintain our asset base, and (ii) we can maintain that increased distribution level over the long term. We intend initially to fund maintenance capital expenditures with cash flow from operations and to fund expansion capital expenditures with cash flow from operations, borrowings or issuances of additional equity and debt securities. Please read "How We Will Make Cash Distributions—Distributions of Available Cash."
Restrictions and Limitations on Cash Distributions. There is no guarantee that our unitholders will receive quarterly distributions from us. While our partnership agreement requires us to distribute all of our available cash quarterly, we do not have a legal obligation to pay distributions at the minimum quarterly distribution rate. Our distribution policy is subject to certain restrictions and may be changed at any time, including as a result of the following factors:
- •
- We may borrow to make distributions to unitholders, for example, in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to pay the distribution at the current level. For example, because we intend to have in place hedging arrangements covering a significant portion of our production, we may be required to pay derivative counterparties the difference between the fixed price and market price of the underlying commodity before we receive the proceeds from the sale of the associated production. Our partnership agreement will not restrict our ability to borrow to pay distributions, but we expect to be subject to restrictions on distributions under our new credit facility.
- •
- We expect our new credit facility to contain certain material financial tests, such as a leverage ratio, a current ratio and an interest coverage ratio, and covenants that we must satisfy. Should we be unable to satisfy these restrictions under our new credit facility, or if we otherwise default under our new credit facility, we would be prohibited from making a distribution to you notwithstanding our stated cash distribution policy. For additional information, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility."
46
- •
- Our general partner will have broad discretion to establish cash reserves for the prudent conduct of our business, including cash reserves for acquisitions and other capital expenditures and anticipated credit needs, as well as for future cash distributions to our unitholders, and the establishment of those cash reserves could result in a reduction in cash distributions from levels we currently anticipate pursuant to our stated cash distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on the unitholders.
- •
- While our partnership agreement requires us to distribute all of our available cash, the agreement, including the provisions requiring us to make cash distributions, may be amended. Although during the subordination period, with certain exceptions, our partnership agreement may not be amended without the approval of the public common unitholders, our partnership agreement can be amended with the approval of a majority of the outstanding common units (including common units held by Venoco and its affiliates) and any Class B units issued upon the reset of incentive distribution rights, if any, voting as a single class after the subordination period has ended.
- •
- We have assumed that our operations will not be subject to material entity level taxation. However, several states, including Texas, have adopted legislation that imposes taxes on the income of limited partnerships.
- •
- Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.
- •
- We intend to reserve and reinvest a portion of our cash generated from operations to develop our existing properties and to acquire additional oil and natural gas properties and other capital assets in order to maintain our asset base. Over the long term, if we do not make sufficient capital expenditures to maintain our asset base, we will be unable to generate an amount of cash from operations sufficient to sustain our distributions at levels we currently anticipate pursuant to our stated cash distribution policy. In such a case, we would expect to reduce our distributions.
- •
- Even if our stated cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.
- •
- We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including reduced demand for oil or natural gas, reduced production from our wells, lower prices for the production we sell, increases in operating or general and administrative expenses, principal and interest payments on any current or future debt, tax expenses, capital expenditures and working capital requirements. Please read "Risk Factors" for a discussion of these factors.
Our Ability to Grow May Depend on Our Ability to Access External Growth Capital. Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, to the extent that our cash generated from operations and cash reserves are inadequate to fund capital expenditures after paying distributions to unitholders, then we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our capital expenditures. To the extent we are unable to finance growth through internal and external sources, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or other capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or
47
increase our per unit distribution level, which in turn may reduce the available cash that we have to distribute on each unit. There are no limitations in our partnership agreement and we expect no limitations under our new credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth capital expenditures would result in increased interest expense, which in turn may reduce the amount of available cash that we have to distribute to our unitholders.
Our Minimum Quarterly Distribution Rate
Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare a minimum quarterly distribution of $0.4375 per unit, or $1.75 per unit per year, to be paid no later than 45 days after the end of each fiscal quarter. This equates to an aggregate cash distribution of $9.3 million per quarter or $37.4 million per year, in each case based on the number of common units and subordinated units outstanding at the closing of this offering. Our ability to make cash distributions at the minimum quarterly distribution rate pursuant to this policy will be subject to the factors described above under the caption "—General—Restrictions and Limitations on Cash Distributions."
The table below sets forth the assumed number of outstanding common units, subordinated units and general partner equivalent units at the closing of this offering and the aggregate distribution amounts payable on such units during the first four complete quarters following the closing of this offering at our initial distribution rate of $0.4375 per unit per quarter ($1.75 per unit on an annualized basis).
At the closing of this offering, our general partner will be entitled to 2% of all distributions that we make prior to our liquidation. In the future, the general partner's initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2% general partner interest. Upon any exercise by the underwriters of their option to purchase additional common units, an equal number of outstanding common units will be purchased from Venoco. Accordingly, our general partner will not be required to make a capital contribution to us in connection with the issuance of those common units in order to maintain its current 2% general partner interest.
| | No Exercise of the Underwriters' Option to Purchase Additional Common Units
| | Full Exercise of the Underwriters' Option to Purchase Additional Common Units
|
---|
| |
| | Quarterly Distribution
| |
| | Quarterly Distribution
|
---|
| | Number of Units
| | One Quarter
| | Annualized
| | Number of Units
| | One Quarter
| | Annualized
|
---|
Publicly held common units | | 9,100,000 | | $ | 3,981,250 | | $ | 15,925,000 | | 10,465,000 | | $ | 4,578,437 | | $ | 18,313,750 |
Common units held by Venoco(1) | | 6,490,714 | | | 2,839,687 | | | 11,358,750 | | 5,125,714 | | | 2,242,500 | | | 8,970,000 |
Subordinated units held by Venoco | | 5,339,286 | | | 2,335,938 | | | 9,343,750 | | 5,339,286 | | | 2,335,938 | | | 9,343,750 |
General partner equivalent units | | 427,143 | | | 186,875 | | | 747,500 | | 427,143 | | | 186,875 | | | 747,500 |
| |
| |
| |
| |
| |
| |
|
| Total | | 21,357,143 | | $ | 9,343,750 | | $ | 37,375,000 | | 21,357,143 | | $ | 9,343,750 | | $ | 37,375,000 |
| |
| |
| |
| |
| |
| |
|
- (1)
- If the underwriters' option to purchase additional common units is exercised, an equivalent number of common units will be redeemed from Venoco. Accordingly, the exercise of the underwriters' option will not affect the total amount of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units.
The subordination period generally will end on the first business day after we have earned and paid at least $0.4375 (the minimum quarterly distribution) on each outstanding common unit and subordinated unit and the related distributions on our general partner's 2% general partner interest for any three consecutive, non-overlapping four-quarter periods ending on or after March 31, 2011. Please read "How We Will Make Cash Distributions—Subordination Period."
48
If distributions on our common units are not paid with respect to any fiscal quarter at the minimum quarterly distribution rate, holders of our common units will generally not be entitled to receive such payments in the future. However, if we have available cash in any future quarter during the subordination period in excess of the amount necessary to make cash distributions to holders of our common units at the minimum quarterly distribution rate, then we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of subordinated units. Please read "How We Will Make Cash Distributions—Subordination Period."
Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or imposed at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above; however, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith.
The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. Please read "The Partnership Agreement—Voting Rights."
We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. If this offering closes on or prior to March 31, 2008, we expect to pay a distribution per common unit to our unitholders on or before August 15, 2008 equal to the minimum quarterly distribution rate prorated for the portion of the quarter ending March 31, 2008 plus the full amount for the quarter ending June 30, 2008.
In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution rate of $0.4375 per unit for each quarter in the four quarters ending March 31, 2009. In the following sections, we present two tables consisting of the following:
- •
- "Unaudited Pro Forma Cash Available to Pay Distributions," in which we present the amount of cash we would have had available for distribution for our fiscal year ended December 31, 2006, and the twelve months ended September 30, 2007, on a pro forma basis after giving effect to the offering and the formation transactions contemplated by this prospectus; and
- •
- "Estimated Cash Available for Distribution," in which we present our estimate of the minimum amount of Adjusted EBITDA necessary for us to pay distributions at the initial distribution rate on all units for the twelve months ending March 31, 2009.
Unaudited Pro Forma Cash Available to Pay Distributions
Our pro forma cash available for distribution generated during the year ended December 31, 2006, would have been approximately $24.4 million. This would have been sufficient to pay a cash distribution of $0.38 per common unit per quarter ($1.53 per unit on an annualized basis), or approximately 88% of the minimum quarterly distribution. We would not have been able to pay any distributions on our subordinated units during that period.
Our pro forma cash available for distribution for the twelve months ended September 30, 2007 would have been approximately $(2.8) million. Therefore, we would not have been able to pay any distributions on our common or subordinated units during that period.
Unaudited pro forma cash available for distribution includes an incremental general and administrative expense we will incur as a result of being a publicly traded partnership, including
49
compensation and benefit expenses of certain additional personnel, costs associated with reports to unitholders, tax return and Schedule K-1 preparation and distribution, fees paid to independent auditors, lawyers, independent petroleum engineers and other professional advisors, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We expect this incremental general and administrative expense initially to total approximately $1.0 million per year.
The following table illustrates, on a pro forma basis, for the year ended December 31, 2006, and for the twelve months ended September 30, 2007, the amount of cash that would have been available for distribution to our unitholders, assuming in each case that the transactions contemplated in this prospectus and other pro forma adjustments described above had occurred as of January 1, 2006. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.
We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the date indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma cash available for distribution only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.
Venoco Acquisition Company, L.P.
Unaudited Pro Forma Cash Available to Pay Distributions
| | Pro Forma Year Ended December 31, 2006
| | Pro Forma Twelve Months Ended September 30, 2007
| |
---|
| | (In thousands, except per unit data)
| |
---|
Net income: | | $ | 29,606 | | $ | 26,943 | |
| Income taxes | | | 14 | | | 123 | |
| Interest expense, net | | | 3,853 | | | 3,853 | |
| Depletion, depreciation and amortization | | | 7,553 | | | 11,229 | |
| Accretion of abandonment liability | | | 843 | | | 928 | |
| |
| |
| |
Adjusted EBITDA(1) | | | 41,869 | | | 43,076 | |
Less: | | | | | | | |
| Cash interest expense, net | | | 3,653 | | | 3,653 | |
| Income taxes | | | 14 | | | 123 | |
| Capital expenditures(2) | | | 12,805 | | | 41,058 | |
| Estimated incremental general and administrative expenses(3) | | | 1,000 | | | 1,000 | |
| |
| |
| |
Pro forma cash available for distribution | | $ | 24,397 | | $ | (2,758 | ) |
| |
| |
| |
Annualized minimum quarterly distribution per unit | | $ | 1.75 | | $ | 1.75 | |
Pro forma cash distributions: | | | | | | | |
| Distributions on publicly held common units | | $ | 15,925 | | $ | 15,925 | |
| Distributions on common units held by Venoco | | | 11,359 | | | 11,359 | |
| Distributions on subordinated units held by Venoco | | | 9,344 | | | 9,344 | |
| Distributions to our general partner | | | 747 | | | 747 | |
| |
| |
| |
| | Total pro forma cash distributions | | $ | 37,375 | | $ | 37,375 | |
| |
| |
| |
Excess (shortfall) | | $ | (12,978 | ) | $ | (40,133 | ) |
| |
| |
| |
- (1)
- Please read "Prospectus Summary—Non-GAAP Financial Measures."
50
- (2)
- These amounts represent actual capital expenditures, excluding amounts spent on acquisitions of oil and natural gas properties, associated with the Partnership Properties for the periods presented. Please read "—Assumptions and Considerations—Capital Expenditures and Expenses" for a discussion of pro forma capital expenditures for the twelve months ended September 30, 2007.
- (3)
- We expect our incremental general and administrative expenses will include costs associated with annual and quarterly reports to unitholders, our annual meeting of unitholders, tax return and Schedule K-1 preparations and distribution, investor relations, registrar and transfer agent fees, incremental director and officer liability insurance costs, independent director compensation, additional accounting and legal fees and SEC reporting and filing requirements.
Estimated Cash Available for Distribution for the Twelve Months Ending March 31, 2009
In order for us to pay the quarterly distributions to our common and subordinated unitholders at the minimum quarterly distribution of $0.4375 per unit on each of our outstanding common units and subordinated units and the related distributions on our general partner's 2% general partner interest for each quarter in the twelve months ending March 31, 2009, we estimate that during that period, we must generate at least $56.7 million in Adjusted EBITDA, which we refer to as "Minimum Estimated Adjusted EBITDA." We believe that we will be able to generate the full amount of our Minimum Estimated Adjusted EBITDA for the twelve months ending March 31, 2009. In "—Assumptions and Considerations" below, we discuss the major assumptions underlying this belief. The Minimum Estimated Adjusted EBITDA should not be viewed as management's projection of the actual Adjusted EBITDA that we will generate during the twelve months ending March 31, 2009. We can give you no assurance that our assumptions will be realized or that we will generate the Minimum Estimated Adjusted EBITDA or the expected level of available cash, in which event we will not be able to pay quarterly distributions on our common and subordinated units and the related distributions on our general partner's 2% general partner interest at the minimum quarterly distribution rate.
When considering our ability to generate the Minimum Estimated Adjusted EBITDA of $56.7 million and how we calculate estimated cash available for distribution, please keep in mind all the risk factors and other cautionary statements under the headings "Risk Factors" and "Forward-Looking Statements," which discuss factors that could cause our results of operations and cash available for distribution to vary significantly from our estimates.
We do not, as a matter of course, make public projections as to future sales, earnings or other results. However, our management has prepared the prospective financial information set forth below in the table entitled "Estimated Cash Available for Distribution" to illustrate our belief that we can generate the Minimum Estimated Adjusted EBITDA necessary for us to have sufficient cash available to allow us to distribute the minimum quarterly distribution on all of our common units and subordinated units and the related distributions on our general partner's 2% general partner interest. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on this prospective financial information.
The prospective information included in this S-1 has been prepared by, and is the responsibility of, Venoco's management. Neither Deloitte & Touche LLP, PricewaterhouseCoopers LLP nor BDO Seidman LLP has examined, compiled or performed any procedures with respect to the accompanying prospective financial information and, accordingly, neither Deloitte & Touche LLP, PricewaterhouseCoopers LLP nor BDO Seidman LLP express an opinion or any other form of assurance with respect thereto. The Deloitte & Touche LLP reports included in this offering document relate to the historical financial information of Venoco Acquisition Company, L.P. Predecessor, Venoco
51
Acquisition Company, L.P. and Venoco Acquisition Company GP, LLC. The PricewaterhouseCoopers LLP report included in this offering document relates solely to the West Montalvo Onshore Operations Statements of Revenues and Direct Operating Expenses. The BDO Seidman LLP report included in this offering document relates solely to the Hastings Complex Statements of Revenues and Direct Operating Expenses. None of these reports extend to the prospective financial information and should not be read to do so.
The assumptions and estimates underlying the prospective financial information are inherently uncertain and, though considered reasonable by the management of our general partner as of the date of its preparation, are subject to a wide variety of significant business, economic, and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information, including, among others, risks and uncertainties. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.
We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient cash available for distribution to allow us to pay the minimum quarterly distribution on all of our outstanding common units and subordinated units and the related distributions on our general partner's 2% general partner interest for the twelve months ending March 31, 2009, should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.
The following table shows how we calculate Minimum Estimated Adjusted EBITDA for the twelve months ending March 31, 2009. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in "—Assumptions and Considerations."
52
Venoco Acquisition Company, L.P.
Estimated Cash Available for Distribution
| | Forecast for Twelve Months Ending March 31, 2009
|
---|
| | (In thousands, except per unit data)
|
---|
Revenue: | | | |
| Oil and natural gas revenues | | $ | 99,094 |
| Commodity derivative gains (losses) | | | — |
| Pipeline revenues | | | 7,680 |
| |
|
| | Total revenues | | | 106,774 |
Operating expenses: | | | |
| Lease operating expenses | | | 31,141 |
| Production and property taxes | | | 2,710 |
| Transportation expense | | | 829 |
| Pipeline operating expense | | | 2,320 |
| Depreciation, depletion and amortization | | | 10,445 |
| Accretion of abandonment liability | | | 953 |
| General and administrative expenses(1) | | | 5,990 |
| |
|
| | Total operating expenses | | | 54,388 |
| |
|
Operating income | | | 52,386 |
Interest expense, net | | | 3,607 |
Income taxes | | | 214 |
| |
|
Net income | | | 48,565 |
| |
|
Adjustments to reconcile net income to Adjusted EBITDA: | | | |
| Add: | | | |
| | Interest expense, net | | | 3,607 |
| | Income taxes | | | 214 |
| | Depreciation, depletion and amortization | | | 10,445 |
| | Accretion of abandonment liability | | | 953 |
| |
|
Estimated Adjusted EBITDA(2) | | | 63,784 |
| |
|
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution: | | | |
| Less: | | | |
| | Cash interest expense, net(3) | | | 3,407 |
| | Income taxes | | | 214 |
| | Estimated maintenance capital expenditures(4) | | | 15,700 |
| | Expansion capital expenditures | | | 8,582 |
| Add: | | | |
| | Borrowings to finance expansion capital expenditures | | | 8,582 |
| |
|
Estimated cash available for distribution | | $ | 44,463 |
| |
|
Annualized minimum quarterly distribution per unit | | $ | 1.75 |
Estimated cash distributions: | | | |
| Distributions on publicly held common units | | $ | 15,925 |
| Distributions on common units held by Venoco | | | 11,359 |
| Distributions on subordinated units held by Venoco | | | 9,344 |
| Distributions to our general partner | | | 747 |
| |
|
| | Total estimated cash distributions | | $ | 37,375 |
| |
|
Excess of estimated cash available for distribution over estimated cash distributions | | $ | 7,088 |
| |
|
Estimated Adjusted EBITDA(2) | | $ | 63,784 |
| Less: | | | |
| | Excess of estimated cash available for distribution over estimated cash distributions | | | 7,088 |
| |
|
| | | Minimum Estimated Adjusted EBITDA necessary to pay estimated cash distributions at the minimum quarterly distribution rate | | $ | 56,696 |
| |
|
- (1)
- Includes an estimated $1.0 million of additional general and administrative expenses we expect to incur as a result of being a publicly traded partnership.
53
- We expect our incremental general and administrative expenses will include costs associated with annual and quarterly reports to unitholders, our annual meeting of unitholders, tax return and Schedule K-1 preparations and distribution, investor relations, registrar and transfer agent fees, incremental director and officer liability insurance costs, independent director compensation, additional accounting and legal fees and SEC reporting and filing requirements.
- (2)
- Please read "Prospectus Summary—Non-GAAP Financial Measures."
- (3)
- Cash interest expense is net of estimated interest income of approximately $5.6 million for the twelve months ending March 31, 2009.
- (4)
- Please read "How We Will Make Cash Distributions—Operating Surplus and Capital Surplus—Estimated Maintenance Capital Expenditures."
Assumptions and Considerations
Based upon the specific assumptions outlined below with respect to the twelve months ending March 31, 2009, we expect to generate Adjusted EBITDA in an amount sufficient to allow us to pay the minimum quarterly distribution on all of our outstanding common units and subordinated units and the related distributions on our general partner's 2% general partner interest for the twelve months ending March 31, 2009, and to establish adequate cash reserves to fund our estimated maintenance capital expenditures. Our estimated cash available for distribution is prepared on a basis consistent with the accounting principles used in the historical financial statements of our predecessor entities.
While we believe that these assumptions are reasonable in light of management's current expectations concerning future events, the estimates underlying these assumptions are inherently uncertain and are subject to significant business, economic, regulatory, environmental and competitive risks and uncertainties that could cause actual results to differ materially from those we anticipate. If our assumptions are not correct, the amount of actual cash available to pay distributions could be substantially less than the amount we currently estimate and could, therefore, be insufficient to allow us to pay the minimum quarterly distribution (absent borrowings under our new credit facility), or any amount, on all of our outstanding common units and subordinated units and the related distributions on our general partner's 2% general partner interest, in which event the market price of our common units may decline substantially. Over the long term, if we do not make sufficient cash expenditures to maintain our asset base, we will be unable to generate an amount of cash from operations sufficient to sustain our distributions at levels we currently anticipate pursuant to our stated cash distribution policy. In such a case, we would expect to reduce our distributions. In addition, decreases in commodity prices from current levels will adversely affect our ability to pay distributions. When reading this section, you should keep in mind the risk factors and other cautionary statements under the headings "Risk Factors" and "Forward-Looking Statements." Any of the risks discussed in this prospectus could cause our actual results to vary significantly from our estimates.
Operations and Revenues
Production. The following table sets forth information regarding net production of oil and natural gas on a pro forma basis for the year ended December 31, 2006 and the twelve months ended September 30, 2007 and on a forecasted basis for the twelve months ending March 31, 2009:
| | Pro Forma for Year Ended December 31, 2006
| | Pro Forma for Twelve Months Ended September 30, 2007
| | Forecast for Twelve Months Ending March 31, 2009
|
---|
Annual production: | | | | | | |
Oil (MBbl) | | 1,140 | | 1,220 | | 1,276 |
Natural gas (MMcf) | | 1,122 | | 1,116 | | 900 |
| Total (MBoe) | | 1,327 | | 1,406 | | 1,426 |
Average daily production: | | | | | | |
Oil (Bbl/d) | | 3,124 | | 3,342 | | 3,495 |
Natural gas (Mcf/d) | | 3,074 | | 3,057 | | 2,465 |
| Total (Boe/d) | | 3,636 | | 3,852 | | 3,906 |
54
We estimate that our oil and natural gas production for the twelve months ending March 31, 2009 will be 1,426 MBoe as compared to 1,406 MBoe on a pro forma basis for the twelve months ended September 30, 2007. The forecasted growth in our production is the result of increased drilling, workover and reactivation activity in 2007 and 2008 in the Hastings Complex and the West Montalvo field as more fully described in "—Capital Expenditures and Expenses."
Prices. The table below illustrates the relationship between oil and natural gas wellhead prices as a percentage of average NYMEX prices on a pro forma basis for the year ended December 31, 2006 and the twelve months ended September 30, 2007 as compared to our forecast for the twelve months ending March 31, 2009:
| |
| |
| |
| |
---|
| | Pro Forma for Year Ended December 31, 2006
| | Pro Forma for Twelve Months Ended September 30, 2007
| | Forecast for Twelve Months Ended March 31, 2009
| |
---|
Average oil sales prices ($/Bbl): | | | | | | | | | | |
NYMEX price | | $ | 66.22 | | $ | 64.70 | | $ | 80.00 | |
Differential to NYMEX (excluding hedge impacts) | | | 8.28 | | | 7.88 | | | 6.90 | |
| |
| |
| |
| |
Wellhead price | | $ | 57.94 | | $ | 56.82 | | $ | 73.10 | |
| |
| |
| |
| |
Wellhead differential percentage to NYMEX price | | | 87.5 | % | | 87.8 | % | | 91.4 | % |
Average natural gas sales prices ($/Mcf): | | | | | | | | | | |
NYMEX price | | $ | 6.99 | | $ | 7.07 | | $ | 7.00 | |
Differential to NYMEX (excluding hedge impacts) | | | 0.84 | | | 0.04 | | | 0.51 | |
| |
| |
| |
| |
Wellhead price | | $ | 6.15 | | $ | 7.03 | | $ | 6.49 | |
| |
| |
| |
| |
Wellhead differential percentage to NYMEX price | | | 88.0 | % | | 99.4 | % | | 92.8 | % |
| Total combined wellhead price ($/Boe) | | $ | 54.98 | | $ | 54.88 | | $ | 69.51 | |
| |
| |
| |
| |
The forecast period utilizes an assumed NYMEX crude oil price of $80.00 per barrel for the forecast period based on NYMEX prices at the time the forecast was developed. The natural gas price utilized was $7.00 per MMBtu based on NYMEX prices at the time the forecast was developed.
Our oil wellhead price as a percentage of the average NYMEX price is expected to average 91.4% for the twelve months ending March 31, 2009 as compared to 87.8% on a pro forma basis for the twelve months ended September 30, 2007. Our natural gas wellhead price as a percentage of the average NYMEX price is expected to average 92.8% for the twelve months ending March 31, 2009 as compared to 99.4% on a pro forma basis for the twelve months ended September 30, 2007.
Hedging. We intend to enter into hedging arrangements in the future with respect to at least 70% of the expected production from our proved developed producing properties over a three- to five-year period in order to reduce our exposure to fluctuations in the prices of oil and natural gas. The forecast assumes that 70% of our oil production is hedged at $80.00 per Bbl and 70% of our natural gas production is hedged at $7.00 per MMBtu.
Oil and Natural Gas Revenues. The following table illustrates the primary components of oil and natural gas revenues on a pro forma basis for the year ended December 31, 2006 and twelve months
55
ended September 30, 2007 and on a forecasted basis for the twelve months ending March 31, 2009 (in thousands):
| |
| |
| |
|
---|
| | Pro Forma for Year Ended December 31, 2006
| | Pro Forma for Twelve Months Ended September 30, 2007
| | Forecast for Twelve Months Ending March 31, 2009
|
---|
Oil: | | | | | | | | | |
| Wellhead revenues | | $ | 66,062 | | $ | 69,311 | | $ | 93,250 |
| Hedging gain (loss) | | | — | | | — | | | — |
| |
| |
| |
|
| Total oil revenues | | $ | 66,062 | | $ | 69,311 | | $ | 93,250 |
| |
| |
| |
|
Natural gas: | | | | | | | | | |
| Wellhead revenues | | $ | 6,900 | | $ | 7,842 | | $ | 5,844 |
| Hedging gain (loss) | | | — | | | — | | | — |
| |
| |
| |
|
| Total natural gas revenues | | $ | 6,900 | | $ | 7,842 | | $ | 5,844 |
| |
| |
| |
|
Oil and natural gas revenues | | $ | 72,962 | | $ | 77,153 | | $ | 99,094 |
| |
| |
| |
|
Sensitivity Analysis. The following table shows estimated Adjusted EBITDA sensitivities under various assumed NYMEX oil and natural gas prices for the twelve months ending March 31, 2009. In addition, the estimated Adjusted EBITDA amounts shown below are based on realized oil prices that take into account our average NYMEX oil and natural gas price differential assumptions of 91.4% and 92.8% of NYMEX, respectively. We have assumed no changes in our production based on changes in prices (in thousands, except per unit, per day amounts and percentages).
Average unhedged NYMEX oil price ($/Bbl) | | $ | 70.00 | | $ | 75.00 | | $ | 80.00 | | $ | 85.00 | |
Average unhedged NYMEX natural gas price ($/Mcf) | | $ | 6.50 | | $ | 6.75 | | $ | 7.00 | | $ | 7.25 | |
Total average production (Boe/d) | | | 3,906 | | | 3,906 | | | 3,906 | | | 3,906 | |
Percentage oil | | | 89.5 | % | | 89.5 | % | | 89.5 | % | | 89.5 | % |
Total oil and natural gas revenues | | $ | 95,472 | | $ | 97,283 | | $ | 99,094 | | $ | 100,905 | |
Pipeline revenues | | | 7,680 | | | 7,680 | | | 7,680 | | | 7,680 | |
Lease operating expenses | | | 31,141 | | | 31,141 | | | 31,141 | | | 31,141 | |
Pipeline operating expense | | | 2,320 | | | 2,320 | | | 2,320 | | | 2,320 | |
Production and property taxes | | | 2,610 | | | 2,660 | | | 2,710 | | | 2,761 | |
Transportation expense | | | 829 | | | 829 | | | 829 | | | 829 | |
General and administrative expenses(1) | | | 5,990 | | | 5,990 | | | 5,990 | | | 5,990 | |
| |
| |
| |
| |
| |
Adjusted EBITDA | | $ | 60,262 | | $ | 62,023 | | $ | 63,784 | | $ | 65,544 | |
| |
| |
| |
| |
| |
- (1)
- Includes an estimated $1.0 million of additional general and administrative expenses we expect to incur as a result of being a publicly traded partnership.
As NYMEX prices decline, the decline in our estimated Adjusted EBITDA will be mitigated due to hedging gains attributable to hedged oil and natural gas production and lower production taxes and price differentials, which are calculated based on a percentage of wellhead prices as opposed to hedged prices.
Pipeline Revenues. Pipeline revenues consist primarily of pipeline transportation revenues we receive from Venoco and third parties for utilization of pipeline capacity of common carrier pipeline owned by us.
56
Capital Expenditures and Expenses
Capital Expenditures. We estimate that our total capital expenditures for the twelve months ending March 31, 2009 will be approximately $24.3 million as compared to $12.8 million and $41.1 million on a pro forma basis for the year ended December 31, 2006 and twelve months ended September 30, 2007, respectively. Of this $24.3 million, approximately $8.6 million will be classified as expansion capital expenditures for projects that will increase future production and proved reserves. The remaining $15.7 million will be classified as maintenance capital expenditures for projects that are designed to maintain current production and proved reserve levels. The forecasted net decrease in capital expenditures as compared to the pro forma capital expenditures for the twelve months ended September 30, 2007 is attributable to the following:
- •
- Hastings Complex. We anticipate a significant reduction in capital expenditures for the Hastings Complex for the twelve months ending March 31, 2009 as compared to the twelve months ended September 30, 2007. Since Venoco acquired the Hastings Complex on March 31, 2006, it has pursued an aggressive field reactivation program including: returning idle wells to production; increasing the lift capacity of existing wells using larger, more efficient pumps; working over and recompleting existing wells in different producing sands; significantly upgrading surface facility fluid handling capacity (160,000 Bbl/d at the time of purchase as compared to approximately 500,000 Bbl/d); and increasing water injection capabilities. Capital expenditures for many of these activities were necessary to accommodate future production growth, but did not directly increase production volumes. Expansion capital expenditures for the twelve months ending March 31, 2009 will be primarily on projects to increase lift capacity in certain of our existing wells by installing more efficient production lift systems. Our maintenance capital for the twelve months ending March 31, 2009 will primarily consist of expenditures for workovers and recompletions of certain of our existing wells as well as continued optimization of our surface facilities. As a result, we expect total capital expenditures for the Hastings Complex for the twelve months ending March 31, 2009 will be approximately $10.5 million, representing a decrease of approximately $23.4 million as compared to total capital expenditures for the twelve months ended September 30, 2007 of $33.9 million.
- •
- West Montalvo field. Partially offsetting our anticipated decline in spending at the Hastings Complex, is an expected increase in capital expenditures relating to a similar reactivation program in the West Montalvo field. Following Venoco's acquisition of the West Montalvo field on May 11, 2007, it initiated a field reactivation program which included: returning idle wells to production; working over and recompleting existing wells; and upgrading well lift systems and processing facilities. Following Venoco's contribution of the Partnership Properties to us at or prior to the closing of this offering, we expect to continue this reactivation program, as well as pursue additional opportunities to increase production and proved reserves in the West Montalvo field. Our 2008 capital program includes the drilling of one or two onshore infill development wells, the continuation of the field reactivation program, including workovers, recompletions and facilities upgrades, as well as a seismic survey for the field. The seismic survey will assist us in designing and optimizing a significant infill development drilling program. We expect the majority of facilities upgrades and workover activity to be completed by December 31, 2008. Accordingly, we anticipate our long-term annual capital requirements will be lower than those forecasted for the twelve months ending March 31, 2009. We expect total capital expenditures for the forecast period will be approximately $7.8 million.
Production and Transportation Expenses. The following table summarizes production and transportation expenses on an aggregate basis and on a per Boe basis for the year ended December 31,
57
2006 and twelve months ended September 30, 2007, on a pro forma basis, and on a forecasted basis for the twelve months ending March 31, 2009 (in thousands, except per Boe amounts):
| |
| |
| |
|
---|
| | Pro Forma for Year Ended December 31, 2006
| | Pro Forma for Twelve Months Ended September 30, 2007
| | Forecast for Twelve Months Ending March 31, 2009
|
---|
Lease operating expenses | | $ | 29,647 | | $ | 31,792 | | $ | 31,141 |
Production and property taxes | | | 1,682 | | | 1,786 | | | 2,710 |
| |
| |
| |
|
| Production expenses | | $ | 31,329 | | $ | 33,578 | | $ | 33,851 |
| |
| |
| |
|
Transportation expense | | $ | 970 | | $ | 958 | | $ | 829 |
Lease operating expenses ($/Boe) | | $ | 22.34 | | $ | 22.61 | | $ | 21.84 |
Production and property taxes ($/Boe) | | | 1.27 | | | 1.27 | | | 1.90 |
| |
| |
| |
|
| Production expenses ($/Boe) | | $ | 23.61 | | $ | 23.88 | | $ | 23.74 |
| |
| |
| |
|
Transportation expense ($/Boe) | | $ | 0.73 | | $ | 0.68 | | $ | 0.58 |
The following table summarizes production and property taxes on an aggregate pro forma basis and as a percentage of wellhead revenues for the year ended December 31, 2006 and the twelve months ended September 30, 2007 and for the twelve months ending March 31, 2009 (in thousands, except percentages):
| |
| |
| |
| |
---|
| | Pro Forma for Year Ended December 31, 2006
| | Pro Forma for Twelve Months Ended September 30, 2007
| | Forecast for Twelve Months Ending March 31, 2009
| |
---|
Wellhead oil and natural gas revenues | | $ | 72,962 | | $ | 77,153 | | $ | 99,094 | |
Production taxes | | | 1,682 | | | 1,786 | | | 2,710 | |
Production taxes as a percentage of wellhead revenues | | | 2.3 | % | | 2.3 | % | | 2.7 | % |
Our production taxes and property taxes are calculated as a percentage of our oil and natural gas wellhead revenues. In general, as prices and volumes increase, our production and property taxes increase and as prices and volumes decrease, our production and property taxes decrease. Additionally, production and property tax percentages vary by state and as revenues by state vary, it can cause increases or decreases in our overall rate.
Our transportation expense consists of third-party pipeline transportation expenses related to our oil and natural gas production.
Pipeline Operating Expense. Pipeline operating expense consists primarily of costs we incur relating to our transportation of oil and natural gas for Venoco and third parties.
Accretion of Abandonment Liability. Asset retirement obligations reflect an accrual of the costs to plug and abandon our wells when they are depleted and related site restoration costs. The charge we take is based on the amount we produce and our estimates of the costs we anticipate to incur for future abandonment and site restoration. Our forecast is based on the production set forth in our Reserve Reports and our estimates of abandonment and restoration costs.
General and Administrative Expenses. We estimate that our general and administrative expenses for the twelve months ending March 31, 2009 will be approximately $6.0 million as compared to approximately $4.0 million and $5.0 million on a pro forma basis for the year ended December 31, 2006 and twelve months ended September 30, 2007, respectively. Our forecasted general and administrative expenses include approximately $1.0 million of incremental general and administrative expenses that we expect to incur as a result of being a public company. These expenses will include
58
costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. At the closing of this offering, we expect to enter into an administrative services agreement with Venoco whereby Venoco will operate our assets and perform other administrative services on our behalf. We will reimburse our general partner and its affiliates for their direct expenses and an allocated portion of their general and administrative expenses for their services. Future employee bonuses and unit-based compensation may adversely affect our cash available for distribution, however, we have made no assumptions with respect to these items in the forecast. Please read "Management—Reimbursement of Expenses of Our General Partner," "—Executive Compensation" and "—Long-Term Incentive Plan."
Net Interest Expense. We estimate that our net interest expense for the twelve months ending March 31, 2009 will be approximately $3.6 million as compared to $3.9 million and $3.9 million on a pro forma basis for the year ended December 31, 2006 and twelve months ended September 30, 2007, respectively. For the twelve months ending March 31, 2009, we expect to have an average debt balance of approximately $157.5 million outstanding under our new credit facility, including approximately $117.5 million related to borrowings used to purchase marketable securities at the closing of this offering. A change of 1% in our estimated interest rate would increase or decrease estimated interest expense for the twelve months ending March 31, 2009 by $1.6 million. Our estimate of net interest expense for the forecasted period is net of interest income of approximately $5.6 million for the twelve months ending March 31, 2009. This interest income is primarily related to income earned on marketable securities we expect to purchase with a portion of the net proceeds from this offering.
Interest expense is calculated on the basis of an anticipated borrowing rate of 8.25%, which is based on an assumed LIBOR rate of 5.0% and an anticipated borrowing spread under our new credit facility of 325 basis points, or bps. This borrowing rate is applied against the average balance outstanding under our new credit facility excluding borrowings secured by marketable securities we expect to purchase with a portion of the net proceeds from this offering.
We estimate that borrowings under our new credit facility associated with our purchase of marketable securities, net of interest income earned on the approximate $117.5 million of such securities, will bear an effective interest rate of 30 bps.
If the underwriters elect to exercise in full their option to purchase additional units, then indebtedness outstanding at the closing of this offering will increase to $184.8 million and net interest expense will increase to $3.7 million, excluding borrowings used to purchase marketable securities.
Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending March 31, 2009 is based on the following significant assumptions related to regulatory, industry and economic factors:
- •
- there will not be any new federal, state or local regulation of portions of the energy industry in which we operate, or an interpretation of existing regulation, that will be materially adverse to our business;
- •
- there will not be any major adverse change in the portions of the energy industry or in general economic conditions; and
- •
- market, insurance and overall economic conditions will not change substantially.
59
HOW WE WILL MAKE CASH DISTRIBUTIONS
Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.
Distributions of Available Cash
General. Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2008, we distribute all of our available cash to unitholders of record on the applicable record date.
Definition of Available Cash. Available cash, for any quarter, consists of all cash on hand and cash equivalents at the end of that quarter:
- •
- less the amount of cash reserves established by the board of directors of our general partner to:
- •
- provide for the proper conduct of our business (including amounts for maintenance and expansion capital expenditures, future debt service requirements and for our anticipated credit needs);
- •
- comply with applicable law, any of our debt instruments or other agreements; or
- •
- provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;
- •
- plus, if our general partner so determines, all additional cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings.
We define working capital borrowings as borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than additional working capital borrowings.
Intent to Distribute the Minimum Quarterly Distribution. We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $0.4375 per unit, or $1.75 per unit on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if doing so would cause an event of default, or if an event of default exists, under our new credit facility. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Facility" for a discussion of the restrictions to be included in our new credit facility that may restrict our ability to make distributions.
General Partner Interest. Initially, our general partner will own a 2% general partner interest and will be entitled to 2% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its then current general partner interest. The general partner's initial 2% interest in these distributions may be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.
Incentive Distribution Rights. Our general partner also currently owns all of our incentive distribution rights. The incentive distribution rights are limited partner interests in us that entitle our
60
general partner to receive increasing percentages, up to a maximum of 25% (including its 2% general partner interest), of the cash we distribute from operating surplus (as defined below) in excess of $0.5031 per unit per quarter. This maximum distribution of 25% does not include any distributions that our general partner may receive on common and subordinated units that it owns. Please read "—Incentive Distribution Rights" for additional information.
Operating Surplus and Capital Surplus
General. All cash we distribute to unitholders will be characterized as either "operating surplus" or "capital surplus." Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.
Operating Surplus. We define operating surplus in the partnership agreement, and it generally means:
- •
- $20.0 million;plus
- •
- all of our cash receipts after the closing of this offering, excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of our equity and debt securities, (3) sales or other dispositions of assets for cash, other than sales of oil and natural gas production, dispositions of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets, (4) the termination of commodity hedge contracts and interest rate swap agreements prior to their respective termination, (5) capital contributions and (6) corporate reorganizations or restructurings;plus
- •
- working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter;plus
- •
- cash distributions paid on equity issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or proved reserves) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset is placed into service or the date that it is abandoned or disposed of;less
- •
- our operating expenditures after the closing of this offering (please read "—Operating Expenditures");less
- •
- the amount of cash reserves established by our general partner to provide funds for future operating and capital expenditures;less
- •
- all working capital borrowings not repaid within twelve months after having been incurred.
If working capital borrowings are not repaid during the twelve-month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.
Because of fluctuations in our working capital, we may make short-term working capital borrowings in order to level out our distributions from quarter to quarter.
As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $20.0 million of cash we receive in the future from non-operating sources such as certain types of asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above,
61
certain cash distributions on equity securities in operating surplus would be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash distributions we receive from non-operating sources.
Part of our business strategy is to limit our exposure to volatility in commodity prices by entering into hedging agreements. In general, all of the payments we make or receive under hedging agreements, including periodic settlement payments, the purchase price of put contracts and payments made or received in connection with the termination of hedging agreements, will be added or deducted in the determination of operating surplus on the date the payment is received or made. Our partnership agreement allows our general partner, with the approval of the conflicts committee of its board of directors, to allocate payments made or received under hedging agreements over multiple periods, or to exclude such payments or receipts from the calculation of operating surplus, if it determines such treatment to be appropriate.
Operating Expenditures. We define operating expenditures in the partnership agreement, and it generally means all of our expenditures, including lease operating expenses, taxes, reimbursements of expenses to our general partner, payments made in the ordinary course of business under interest rate and commodity hedging arrangements, estimated maintenance capital expenditures, repayment of working capital borrowings and debt service payments. Operating expenditures will not include:
- •
- actual repayment of working capital borrowings deducted from operating surplus that were deemed to have been repaid at the end of the twelve-month period following the borrowing;
- •
- payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;
- •
- actual maintenance capital expenditures;
- •
- expansion capital expenditures (as described below);
- •
- payment of transaction expenses relating to interim capital transactions (please read "—Capital Surplus"); or
- •
- distributions to partners.
Maintenance Capital Expenditures. For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain over the long term our asset base, which includes our oil and natural gas properties, our pipelines and our other capital assets. Examples of maintenance capital expenditures include capital expenditures to maintain our current production levels, bring our non-producing reserves into production, such as drilling and completion costs, enhanced recovery costs and other construction costs, and costs to acquire reserves that replace the reserves we expect to produce in the future. Asset retirement obligations, including plugging and abandoning wells, site restoration and similar costs will also be considered maintenance capital expenditures.
Maintenance capital expenditures will also include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a replacement asset during the period from such financing until the earlier to occur of the date any such replacement asset is put into service or the date that it is disposed of or abandoned.
Estimated Maintenance Capital Expenditures. Our general partner will be required to estimate the average maintenance capital expenditures we will make over the long term, and deduct that estimate in calculating operating surplus. Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus (as described below) if we subtracted our actual maintenance capital expenditures when we calculate operating surplus. Accordingly, to eliminate the effect of these
62
fluctuations on operating surplus, our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain, over the long term, our asset base, which includes our oil and natural gas properties, our pipelines and our other capital assets, be subtracted in calculating operating surplus each quarter as opposed to the actual amounts we spend. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of our general partner at least once a year, provided that any change is approved by the conflicts committee of our general partner. The estimate will be made on a regular basis and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read "Our Cash Distribution Policy and Restrictions on Distributions."
The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:
- •
- it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units and the related distribution on our general partner's 2% general partner interest for that quarter and subsequent quarters;
- •
- it will increase our ability to distribute as operating surplus cash we receive from non-operating sources; and
- •
- it will be more difficult for us to raise our distribution above the minimum quarterly distribution rate and pay incentive distributions to our general partner.
Expansion Capital Expenditures. Expansion capital expenditures are those capital expenditures that we expect will increase our asset base over the long term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development and exploitation of an existing leasehold interest, to the extent such expenditures are incurred to increase our production and our oil and natural gas properties. Expansion capital expenditures will also include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of such capital improvement during the period from such financing until the earlier to occur of the date any such capital improvement is placed into service or the date that it is disposed of or abandoned.
As described above, none of actual maintenance capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because actual maintenance capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction, replacement or improvement of a capital asset (such as proved reserves or equipment) during the period from such financing until the earlier to occur of the date any such capital asset is placed into service or the date that it is disposed of or abandoned, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of average maintenance capital expenditures, to the extent such interest payments and equity distributions are included in estimated maintenance capital expenditures).
Capital Surplus. We also define capital surplus in the partnership agreement and in "—Characterization of Cash Distributions" below, and it will generally be determined only by the following, which we call "interim capital transactions":
- •
- borrowings that are not working capital borrowings;
- •
- sales of our equity and debt securities;
63
- •
- sales or other dispositions of assets for cash, other than sales of oil and natural gas production, dispositions of assets made in connection with plugging and abandoning wells and site restoration, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets;
- •
- the termination of interest rate hedge contracts or commodity hedge contracts prior to the termination date specified therein;
- •
- capital contributions received; and
- •
- corporate reorganizations or restructurings.
Characterization of Cash Distributions. Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available cash. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.
Subordination Period
General. Our partnership agreement provides that, during the subordination period (which will commence at the closing of this offering and will end as described below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.4375 per unit, which is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed to the common units.
Subordination Period. The subordination period will extend until the first day of any quarter beginning after March 31, 2011 that each of the following tests are met:
- •
- distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and the 2% general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
- •
- the "adjusted operating surplus" (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis during those periods; and
- •
- there are no arrearages in payment of the minimum quarterly distribution on the common units.
The subordination period will also end, and each subordinated unit will immediately convert into one common unit, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal. In those circumstances, any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished and the general partner will have the right to convert its 2% general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
64
Conversion of Subordinated Units Upon Expiration of the Subordination Period. When the subordination period expires, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash.
Adjusted Operating Surplus. We define adjusted operating surplus in the partnership agreement, and for any period it generally means:
- •
- operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the second bullet point under "—Operating Surplus and Capital Surplus—Operating Surplus" above);less
- •
- any net increase in working capital borrowings with respect to that period;less
- •
- any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period;plus
- •
- any net decrease in working capital borrowings with respect to that period;plus
- •
- any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus is calculated using estimated maintenance capital expenditures, rather than actual maintenance capital expenditures and, to the extent the estimated amount for a period is less than the actual amount, the cash generated from operations during that period would be less than adjusted operating surplus.
Distributions of Available Cash from Operating Surplus During the Subordination Period
Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:
- •
- first, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;
- •
- second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;
- •
- third, 98% to the subordinated unitholders, pro rata, and 2% to the general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and
- •
- thereafter, in the manner described in "Incentive Distribution Rights" below.
The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
Distributions of Available Cash from Operating Surplus After the Subordination Period
Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:
- •
- first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and
- •
- thereafter, in the manner described in "—Incentive Distribution Rights" below.
65
The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
Incentive Distribution Rights
Incentive distribution rights represent the right to receive an increasing percentage (13% and 23%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.
If for any quarter:
- •
- we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and
- •
- we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in the payment of the minimum quarterly distribution;
then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:
- •
- first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives a total of $0.5031 per unit for that quarter (the "first target distribution");
- •
- second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives a total of $0.5469 per unit for that quarter (the "second target distribution"); and
- •
- thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.
The preceding discussion is based on the assumptions that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
Percentage Allocations of Available Cash from Operating Surplus
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2% general partner interest and assume our general partner has contributed any additional capital required to maintain its 2% general partner interest and has not transferred its incentive distribution rights.
| |
| | Marginal Percentage Interest in Distributions
| |
---|
| | Total Quarterly Distribution per Unit Target Amount
| | Unitholders
| | General Partner
| |
---|
Minimum Quarterly Distribution | | $0.4375 | | 98 | % | 2 | % |
First Target Distribution | | up to $0.5031 | | 98 | % | 2 | % |
Second Target Distribution | | above $0.5031 up to $0.5469 | | 85 | % | 15 | % |
Thereafter | | above $0.5469 | | 75 | % | 25 | % |
66
General Partner's Right to Reset Incentive Distribution Levels
Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be based. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the level to which they are entitled for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount prior to the reset and the target distribution levels prior to the reset such that the holder of the incentive distribution right will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this reset event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to the holder of the incentive distribution right.
In connection with a reset of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued Class B units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two consecutive quarters immediately preceding the reset event as compared to the average cash distributions per common unit during this period.
The number of Class B units that our general partner would be entitled to receive from us in connection with a reset of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of the reset election divided by (y) the average of the amount of cash distributed per common unit during each of those two quarters. Each Class B unit will be convertible into one common unit at the election of the holder of the Class B unit at any time following the first anniversary of the issuance of these Class B units.
Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two consecutive quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:
- •
- first, 98% to all unitholders, pro rata, and 2% to the general partner, until each unitholder receives an amount equal to 115% of the reset minimum quarter distribution for that quarter;
- •
- second, 85% to all unitholders, pro rata, and 15% to the general partner, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for that quarter; and
- •
- thereafter, 75% to all unitholders, pro rata, and 25% to the general partner.
67
The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various levels of cash distribution pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering as well as following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.60.
| |
| | Marginal Percentage Interest in Distribution
| |
|
---|
| | Quarterly Distribution per Unit Prior to Reset
| | Quarterly Distribution per Unit Following Hypothetical Reset
|
---|
| | Unitholders
| | General Partner
|
---|
Minimum Quarterly Distribution | | $0.4375 | | 98 | % | 2% | | $0.60 |
First Target Distribution | | up to $0.5031 | | 98 | % | 2% | | up to $0.69(1) |
Second Target Distribution | | above $0.5031 up to $0.5469 | | 85 | % | 15% | | above $0.69 up to $0.75(2) |
Thereafter | | above $0.5469 | | 75 | % | 25% | | above $0.75 |
- (1)
- This amount is 115% of the hypothetical reset minimum quarterly distribution.
- (2)
- This amount is 125% of the hypothetical reset minimum quarterly distribution.
The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for a quarter for the two quarters immediately preceding the reset event. The table assumes that there are 20,930,000 common units outstanding, that our general partner maintain its 2% general partner interest, and that the average distribution to each common unit is $0.60 for the two consecutive quarters immediately preceding the reset.
| |
| |
| | General Partner Cash Distributions Prior to Reset
| |
|
---|
| |
| | Common Unitholders Cash Distribution Prior to Reset
| |
|
---|
| | Quarterly Distribution per Unit Prior to Reset
| | Class B Units
| | 2% General Partner Interest
| | IDRs
| | Total
| | Total Distributions
|
---|
Minimum Quarterly Distribution | | $0.4375 | | $ | 9,156,875 | | — | | $ | 186,875 | | $ | — | | $ | 186,875 | | $ | 9,343,750 |
First Target Distribution | | up to $0.5031 | | | 1,373,008 | | — | | | 28,021 | | | — | | | 28,021 | | | 1,401,029 |
Second Target Distribution | | above $0.5031 up to $0.5469 | | | 916,734 | | — | | | 21,570 | | | 140,206 | | | 161,777 | | | 1,078,511 |
Thereafter | | above $0.5469 | | | 1,111,383 | | — | | | 29,637 | | | 340,824 | | | 370,461 | | | 1,481,844 |
| | | |
| |
| |
| |
| |
| |
|
| | | | $ | 12,558,000 | | — | | $ | 266,103 | | $ | 481,030 | | $ | 747,134 | | $ | 13,305,134 |
The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner with respect to the quarter in which the reset occurs. The table assumes that as a result of the reset there are 20,930,000 common units and 801,717 Class B units outstanding, that our general partner maintains its 2% general partner interest and that the average distribution to each common unit is $0.60. The number of Class B units was calculated by dividing (x) the $481,030 received by the general partner in respect of its incentive distribution rights, as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two quarters prior to the reset as shown in the table above by (y) the $0.60 of available
68
cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.
| |
| |
| | General Partner Cash Distributions After Reset
| |
|
---|
| |
| | Common Unitholders Cash Distribution After Reset
| |
|
---|
| | Quarterly Distribution per Unit Following Hypothetical Reset
| | Class B Units
| | 2% General Partner Interest
| | IDRs
| | Total
| | Total Distributions
|
---|
Minimum Quarterly Distribution | | $0.60 | | $ | 12,558,000 | | $ | 481,030 | | $ | 266,103 | | $ | — | | $ | 747,133 | | $ | 13,305,133 |
First Target Distribution | | up to $0.69(1) | | | — | | | — | | | — | | | — | | | — | | | — |
Second Target Distribution | | above $0.69 up to $0.75(2) | | | — | | | — | | | — | | | — | | | — | | | — |
Thereafter | | above $0.75 | | | — | | | — | | | — | | | — | | | — | | | — |
| | | |
| |
| |
| |
| |
| |
|
| | | | $ | 12,558,000 | | $ | 481,030 | | $ | 266,103 | | $ | — | | $ | 747,133 | | $ | 13,305,133 |
- (1)
- This amount is 115% of the hypothetical reset minimum quarterly distribution.
- (2)
- This amount is 125% of the hypothetical reset minimum quarterly distribution.
Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.
Distributions from Capital Surplus
How Distributions from Capital Surplus Will Be Made. Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:
- •
- first, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;
- •
- second, 98% to the common unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and
- •
- thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.
The preceding discussion is based on the assumption that our general partner maintains its 2% general partner interest and that we do not issue additional classes of equity securities.
Effect of a Distribution from Capital Surplus. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
69
Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 75% being paid to the holders of units and 25% to the general partner. The percentage interests shown for our general partner include its 2% general partner interest and assume the general partner has not transferred any of the incentive distribution rights and that we do not issue additional classes of equity securities.
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels
In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:
- •
- the minimum quarterly distribution;
- •
- the target distribution levels;
- •
- the unrecovered initial unit price; and
- •
- the number of common units into which a subordinated unit is convertible.
For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50% of its initial level and each subordinated unit would be convertible into two common units. Our partnership agreement prohibits us from making any adjustment by reason of the issuance of additional units for cash or property.
In addition, if legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction or a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to a material amount of entity-level taxation for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter will be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus the general partner's estimate of our aggregate liability for the quarter for the income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.
Distributions of Cash upon Liquidation
General. If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.
The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. There may not, however, be sufficient gain upon our liquidation to enable the holders
70
of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.
Maintenance of Capital Accounts. We will maintain capital accounts for each of our partners in accordance with the Treasury Regulation Sections under Section 704 of the Internal Revenue Code. A common unitholder's initial capital account will be credited with the amount he paid for his common units, and the general partner's initial capital account will be credited with the fair market value of the property contributed by the general partner in exchange for all of the general partner's interests in us. Thereafter, the Treasury Regulations provide that a partner's capital account must be increased by (i) any additional amount of money (or fair market value of property) that such partner has contributed to the partnership and (ii) such partner's distributive share of partnership income and gain, including simulated gain and income and gain that is exempt from tax, and decreased by (x) the amount of money (or fair market value of property) distributed to such partner by the partnership, (y) such partner's distributive share of certain partnership expenditures that are neither deductible nor properly capitalized and (z) such partner's distributive share of partnership loss and deduction, including simulated loss and simulated depletion.
Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:
- •
- first, to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;
- •
- second, 98% to the common unitholders, pro rata, and 2% to our general partner, until the capital account for each common unit is equal to the sum of: (1) the unrecovered initial unit price; (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (3) any unpaid arrearages in payment of the minimum quarterly distribution;
- •
- third, 98% to the subordinated unitholders, pro rata, and 2% to our general partner until the capital account for each subordinated unit is equal to the sum of: (1) the unrecovered initial unit price; and (2) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;
- •
- fourth, 98% to all unitholders, pro rata, and 2% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to our general partner, for each quarter of our existence;
- •
- fifth, 85% to all unitholders, pro rata, and 15% to our general partner, until we allocate under this paragraph an amount per unit equal to: (1) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (2) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, and 15% to our general partner for each quarter of our existence; and
- •
- thereafter, 75% to all unitholders, pro rata, and 25% to our general partner.
The percentage interests set forth above for our general partner include its 2% general partner interest and assume that our general partner has not transferred any of the incentive distribution rights and that we did not issue additional classes of equity securities.
71
If the aggregate amount of a partner's distributions and his allocable share of losses, including simulated loss and simulated depletion, exceed such partner's aggregate capital contributions and his distributive share of income and gain, including simulated gain and income and gain that is exempt from tax, his capital account balance could be less than zero. Nonetheless, our partnership agreement includes specific allocations intended to prevent a limited partner from having a negative capital account. Only our general partner has an obligation to restore a negative capital account upon the liquidation of the partnership.
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the third bullet point above will no longer be applicable.
Manner of Adjustments for Losses. If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:
- •
- first, 98% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;
- •
- second, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and
- •
- thereafter, 100% to our general partner.
If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.
Adjustments to Capital Accounts. Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and our general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in our general partner's capital account balances equaling the amount they would have been if no earlier positive adjustments to the capital accounts had been made.
72
SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA
The following table shows selected historical financial data of Venoco Acquisition Company, L.P. Predecessor, our predecessor, and pro forma financial data of Venoco Acquisition Company, L.P. for the periods and as of the dates presented. The audited financial statements of Venoco Acquisition Company, L.P. Predecessor are comprised of certain of Venoco's oil and natural gas assets, liabilities and operations, which Venoco will contribute to us at or prior to the closing of this offering. Due to the factors described in "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations—Factors Affecting Comparability of Future Results," our future results of operations will not be comparable to our predecessor's historical results. The selected historical financial data as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006 are derived from the audited financial statements of our predecessor included elsewhere in this prospectus. The selected historical financial data presented as of September 30, 2007 and for the nine months ended September 30, 2006 and 2007 are derived from the unaudited financial statements of Venoco Acquisition Company, L.P. Predecessor included elsewhere in this prospectus. The selected historical financial data includes the results of acquired properties from their dates of acquisition, including our interest in the Hastings Complex from March 31, 2006 and our interest in the West Montalvo field from May 11, 2007.
The carve out financial statements of our predecessor are comprised of oil and natural gas assets, liabilities and operations currently owned by Venoco, which we will acquire upon the completion of this offering. The table below does not include selected balance sheet or statement of operations data for our predecessor as of or for the years ended December 31, 2002 and 2003. A combination of factors results in our inability to provide the 2002 and 2003 selected balance sheet and statement of operations information without unreasonable effort and expense. These factors include: (1) the predecessor was not accounted for as a separate entity, subsidiary or division of Venoco, and as a result, balance sheets and statements of operations of the predecessor for 2002 and 2003 were not prepared and do not exist, (2) Venoco converted its historical accounting system during 2005 and accessing information in the predecessor's prior accounting system is difficult, and (3) as a result of employee turnover, the time and costs associated with preparing 2002 and 2003 balance sheets and statements of operations for the predecessor would be excessive and unreasonable. We do not believe that the omission of the selected balance sheet and statement of operations data for 2002 and 2003 would have a material impact on a reader's understanding of our financial results and related trends.
The selected pro forma financial data presented for the year ended December 31, 2006 and as of and for the nine months ended September 30, 2007 are derived from the unaudited pro forma financial statements of Venoco Acquisition Company, L.P. included elsewhere in this prospectus. The unaudited pro forma balance sheet data as of September 30, 2007 assume the transactions listed below occurred on September 30, 2007. The unaudited pro forma statement of operations data for the year ended December 31, 2006 and the nine months ended September 30, 2007 assume the transactions listed below occurred on January 1, 2006. We expect to incur incremental general and administrative ("G&A") expenses of approximately $1.0 million per year as a result of being a publicly traded partnership. These expenses are not reflected in our historical financial statements or in our unaudited pro forma financial statements.
The unaudited pro forma financial statements of Venoco Acquisition Company, L.P. give effect to the following transactions:
- •
- the acquisitions of the Hastings Complex and the onshore portion of the West Montalvo field;
73
- •
- the contribution of the Partnership Properties to us by Venoco;
- •
- the issuance to Venoco of 6,490,714 common units and 5,339,286 subordinated units, representing an aggregate 55.4% limited partner interest in us, a 2% general partner interest in us and all of our incentive distribution rights;
- •
- our sale of 9,100,000 common units to the public and the application of the net proceeds of approximately $167.5 million as described in "Use of Proceeds;" and
- •
- our borrowing of approximately $157.5 million ($117.5 million of which will be secured by marketable securities that we intend to purchase with a portion of the net proceeds of this offering) under our new credit facility, the net proceeds of which will be distributed to Venoco.
The selected pro forma financial information should not be considered as indicative of the historical results we would have had if the transactions described above had been completed on the dates indicated or the results we will have after this offering. You should read the following table in conjunction with "Prospectus Summary—Formation Transactions and Partnership Structure," "Use of Proceeds," "Management's Discussion and Analysis of Financial Condition and Results of Operations," the historical carve out financial statements of Venoco Acquisition Company, L.P. Predecessor and the unaudited pro forma financial statements of Venoco Acquisition Company, L.P. included elsewhere in this prospectus. Among other things, those historical and pro forma financial statements include more detailed information regarding the basis of presentation for the following information.
The following table includes the non-GAAP financial measure of Adjusted EBITDA for the periods presented. This measure is not calculated or presented in accordance with generally accepted accounting principles, or GAAP. Please read "Prospectus Summary—Non-GAAP Financial Measures"
74
for an explanation of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income and net cash provided by operating activities.
| | Venoco Acquisition Company, L.P. Predecessor
| | Pro Forma Venoco Acquisition Company, L.P.
|
---|
| |
| |
| |
| | Nine Months Ended September 30,
| |
| |
|
---|
| | Years Ended December 31,
| |
| | Nine Months Ended September 30, 2007
|
---|
| | Year Ended December 31, 2006
|
---|
| | 2004
| | 2005
| | 2006
| | 2006
| | 2007
|
---|
| | (In thousands)
|
---|
Statement of Operations Data: | | | | | | | | | | | | | | | | | | | | | |
Oil and natural gas revenues | | $ | 27,230 | | $ | 37,879 | | $ | 58,587 | | $ | 42,739 | | $ | 56,056 | | $ | 72,962 | | $ | 59,034 |
Pipeline revenues | | | 6,429 | | | 6,235 | | | 7,595 | | | 5,767 | | | 5,695 | | | 7,595 | | | 5,695 |
| |
| |
| |
| |
| |
| |
| |
|
| Total revenues | | | 33,659 | | | 44,114 | | | 66,182 | | | 48,506 | | | 61,751 | | | 80,557 | | | 64,729 |
Lease operating expenses | | | 12,360 | | | 14,339 | | | 24,031 | | | 17,410 | | | 22,617 | | | 29,647 | | | 23,854 |
Production and property taxes | | | 263 | | | 365 | | | 1,473 | | | 936 | | | 1,249 | | | 1,682 | | | 1,249 |
Transportation expense | | | 567 | | | 707 | | | 970 | | | 695 | | | 684 | | | 970 | | | 684 |
Pipeline operating expense | | | 1,441 | | | 1,617 | | | 2,341 | | | 1,799 | | | 1,536 | | | 2,341 | | | 1,536 |
Depreciation, depletion and amortization | | | 2,299 | | | 2,771 | | | 5,542 | | | 4,293 | | | 7,447 | | | 7,553 | | | 7,947 |
Accretion of abandonment liability | | | 514 | | | 627 | | | 716 | | | 524 | | | 682 | | | 843 | | | 714 |
General and administrative expenses, net of amounts capitalized | | | 1,324 | | | 1,984 | | | 4,048 | | | 2,763 | | | 3,696 | | | 4,048 | | | 3,696 |
Interest expense, net | | | 525 | | | 261 | | | 5,648 | | | 3,881 | | | 5,551 | | | 3,853 | | | 2,890 |
Loss on extinguishment of debt | | | 457 | | | — | | | — | | | — | | | 1,061 | | | — | | | — |
| |
| |
| |
| |
| |
| |
| |
|
| Total financing costs | | | 982 | | | 261 | | | 5,648 | | | 3,881 | | | 6,612 | | | 3,853 | | | 2,890 |
Income tax provision | | | — | | | — | | | 14 | | | 12 | | | 91 | | | 14 | | | 91 |
| |
| |
| |
| |
| |
| |
| |
|
Net income | | $ | 13,909 | | $ | 21,443 | | $ | 21,399 | | $ | 16,193 | | $ | 17,137 | | $ | 29,606 | | $ | 22,068 |
| |
| |
| |
| |
| |
| |
| |
|
Balance Sheet Data (end of period): | | | | | | | | | | | | | | | | | | | | | |
Cash and cash equivalents | | $ | — | | $ | — | | $ | — | | | | | $ | — | | | | | $ | 5,000 |
Marketable securities | | | — | | | — | | | — | | | | | | — | | | | | | 117,488 |
Total assets | | | 37,897 | | | 42,555 | | | 95,063 | | | | | | 160,788 | | | | | | 282,988 |
Long-term debt | | | — | | | 4,174 | | | 49,965 | | | | | | 83,141 | | | | | | 157,488 |
Owner's/Partners' equity | | | 26,759 | | | 26,993 | | | 26,301 | | | | | | 47,795 | | | | | | 95,648 |
Other Financial Data (unaudited): | | | | | | | | | | | | | | | | | | | | | |
Adjusted EBITDA(1) | | $ | 17,704 | | $ | 25,102 | | $ | 33,319 | | $ | 24,903 | | $ | 31,969 | | $ | 41,869 | | $ | 33,710 |
Cash Flow Data: | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by (used in): | | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 16,900 | | $ | 24,036 | | $ | 27,009 | | $ | 21,634 | | $ | 26,740 | | | | | | |
| Investing activities | | | (5,687 | ) | | (6,953 | ) | | (48,474 | ) | | (62,163 | ) | | (63,497 | ) | | | | | |
| Financing activities | | | (11,213 | ) | | (17,083 | ) | | 21,465 | | | 40,529 | | | 36,757 | | | | | | |
- (1)
- Please read "Prospectus Summary—Non-GAAP Financial Measures" for our definition of Adjusted EBITDA, a reconciliation of Adjusted EBITDA to the comparable GAAP measures and a discussion of why management uses the non-GAAP financial measure.
75
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with the "Selected Historical and Pro Forma Financial Data" and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the factors discussed below and elsewhere in this prospectus, particularly in "Risk Factors" and "Forward-Looking Statements," all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. In this section, unless indicated otherwise, references to "we," "our" and "us" used in a historical context refer to, and the analysis and discussion of the historical financial results reflect the results of operations and financial condition of, Venoco Acquisition Company, L.P. Predecessor.
Overview
We are a growth-oriented Delaware limited partnership formed on September 25, 2007 by Venoco, Inc. (NYSE: VQ) to acquire, exploit, develop and produce oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are principally located in coastal California and onshore Texas. Most of our oil and natural gas properties are located in large, mature fields with well-known geologic characteristics and long production histories. Our properties generally have stable and predictable production profiles and long reserve lives.
As of December 31, 2006, the Partnership Properties had estimated proved reserves of 21.2 MMBoe, of which 86.2% were oil and 81.1% were classified as proved developed, and had a reserve-to-production ratio of 15.1 years. As of September 30, 2007, the Partnership Properties consisted primarily of working interests in 325 gross producing wells, with a 38.5% average working interest. We operate interests that accounted for 80.8% of our pro forma production for the nine months ended September 30, 2007. The Partnership Properties represented 21.5% of Venoco's estimated proved reserves as of December 31, 2006, including reserves attributable to properties acquired by Venoco after that date. The Partnership Properties also include five associated oil or natural gas pipeline systems.
Our historical financial statements reflect the results of operations and financial condition of Venoco Acquisition Company, L.P. Predecessor as of December 31, 2005 and 2006 and for the years ended December 31, 2004, 2005 and 2006, and as of September 30, 2007 and for the nine months ended September 30, 2006 and 2007, as though Venoco had operated the Partnership Properties as a separate entity.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations. Among these measures are the following:
- •
- volumes of oil and natural gas produced and realized prices on the sale of oil and natural gas;
- •
- effects of the use of hedging arrangements;
- •
- expenses incurred in the operation of oil and natural gas properties;
- •
- production and property taxes and general and administrative expenses.
76
Significant Operational Factors
Operational factors that have affected our results of operations and financial condition since January 1, 2004 include the following:
Acquisitions. Acquired properties are included in our historical financial statements from the date of acquisition. Significant acquisitions completed since January 1, 2004 are discussed below:
- •
- West Montalvo field—Venoco acquired the West Montalvo field, the onshore portion of which is included in the Partnership Properties, in May 2007. Our interest in the field represented 21% of our pro forma proved reserves as of December 31, 2006 and 13% of our pro forma production for the year ended December 31, 2006.
- •
- Hastings Complex—Venoco acquired the Hastings Complex in March 2006 as part of its acquisition of TexCal Energy (LP) LLC. A 44% interest in the Hastings Complex is included in the Partnership Properties. That interest represented 33% of our proved reserves as of December 31, 2006 and 27% of our pro forma production for the year ended December 31, 2006.
- •
- Other—Venoco acquired its interest in the Union Island field in July 2004 and the Union Island pipeline in December 2005.
Production. As a result of the acquisitions discussed above and our exploitation and development activities, our production has increased significantly, from an average of 2,063 Boe/d in 2004 to 2,161 in 2005, 2,940 Boe/d in 2006 and 3,601 Boe/d in the first nine months of 2007.
Realized Prices. The prices we receive for our production vary based on changes affecting general market benchmarks, such as New York Mercantile Exchange, or NYMEX, prices, and on changes in the differentials specifically applicable to our production due to (i) its location relative to refining and consuming markets and (ii) its quality in terms of its gravity, sulfur content and/or Btu content. As described in "—Factors Affecting Comparability of Future Results—Derivative Transactions," our historical financial statements do not reflect the effect of any hedging transactions. Significant increases in the prices we received for our oil production contributed to our revenue growth in 2005 and 2006.
Production Expenses. Production expenses are the costs incurred in the operation of our producing properties and are primarily composed of lease operating expense, workover costs and production, severance and property taxes. A significant portion of our operating costs are variable and correlated with the level of hydrocarbons and water produced. For example, we incur power costs in connection with our oil and natural gas production activities, such as separation and water treatment costs, and these costs are highly correlated with our level of production. However, certain costs, such as materials and supplies and direct labor, generally remain relatively fixed, but can fluctuate depending on the level of activities performed.
Factors Affecting Comparability of Future Results
You should read the discussion of our financial condition and results of operations in conjunction with our historical and pro forma financial statements included elsewhere in this prospectus. Our future results of operations and financial condition are likely to differ significantly from the results of operations and financial condition reflected in our historical financial statements due to changes in our business, commodity prices and general market conditions and other factors (including those described in "Risk Factors"), and because our historical financial statements do not reflect the following matters:
Derivative Transactions. Our historical financial statements do not reflect any costs or benefits related to derivative transactions. However, as part of our business strategy, we intend to enter into hedging arrangements in the future with respect to at least 70% of the expected production from our proved developed producing reserves over a three- to five-year period in order to reduce our exposure
77
to fluctuations in the prices of oil and natural gas. Please read "—Quantitative and Qualitative Disclosures About Market Risk" for further information regarding our hedging strategy.
General and Administrative Expenses. We expect to incur approximately $1.0 million per year in additional general and administrative expenses as a result of becoming a publicly traded partnership. These costs include incremental fees associated with our annual and quarterly reporting, tax returns, Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, insurance costs and accounting and legal services. These additional general and administrative expenses are not reflected in our historical financial statements.
At the closing of this offering, we will enter into an administrative services agreement with Venoco and our general partner pursuant to which Venoco and its subsidiaries will perform certain administrative services for us and will be reimbursed for the costs they incur in providing those services.
Production Expenses. Our historical financial statements reflect estimated direct and indirect overhead costs related to the operation of the Partnership Properties during the periods shown. However, at the closing of this offering we will enter into joint operating and production handling agreements relating to the operation of the wells in the South Ellwood field in which we have an interest pursuant to which we will pay Venoco overhead charges associated with operating those wells. Please read "Certain Relationships and Related Party Transactions" for a description of these agreements. The costs we incur pursuant to these agreements are not reflected in our historical financial statements and may not be comparable to the estimated direct and indirect overhead costs that are included in those financial statements.
Interest Expense. Our historical financial statements reflect an allocation of Venoco's debt and debt related costs; however, Venoco does not intend to transfer any of its historical debt to us. We expect to borrow approximately $157.5 million at the closing of this offering ($117.5 million of which will be secured by marketable securities which we intend to purchase with a portion of the net proceeds of this offering) pursuant to a credit facility to be entered into at that time. The expected terms of that agreement are described in "—Liquidity and Capital Resources."
78
Results of Operations
The following table sets forth selected financial and operating data for the periods indicated.
| | Years Ended December 31,
| | Nine Months Ended September 30,
|
---|
| | 2004
| | 2005
| | 2006
| | 2006
| | 2007
|
---|
Production volume: | | | | | | | | | | | | | | | |
| Oil (MBbl) | | | 628 | | | 607 | | | 905 | | | 638 | | | 846 |
| Natural gas (MMcf) | | | 761 | | | 1,090 | | | 1,009 | | | 751 | | | 820 |
| MBoe | | | 755 | | | 789 | | | 1,073 | | | 764 | | | 983 |
Daily average production volume: | | | | | | | | | | | | | | | |
| Oil (Bbl/d) | | | 1,716 | | | 1,663 | | | 2,480 | | | 2,338 | | | 3,101 |
| Natural gas (Mcf/d) | | | 2,078 | | | 2,986 | | | 2,763 | | | 2,753 | | | 3,003 |
| Boe/d | | | 2,063 | | | 2,161 | | | 2,940 | | | 2,797 | | | 3,601 |
Realized price (in dollars): | | | | | | | | | | | | | | | |
| Oil (per Bbl) | | $ | 36.12 | | $ | 49.57 | | $ | 57.77 | | $ | 60.31 | | $ | 59.71 |
| Natural gas (per Mcf) | | | 5.97 | | | 7.15 | | | 6.25 | | | 5.64 | | | 6.73 |
| Per Boe | | | 36.07 | | | 48.03 | | | 54.59 | | | 55.97 | | | 57.02 |
Expense per Boe: | | | | | | | | | | | | | | | |
| Lease operating expenses | | $ | 16.37 | | $ | 18.18 | | $ | 22.39 | | $ | 22.80 | | $ | 23.01 |
| Production and property taxes | | | 0.35 | | | 0.46 | | | 1.37 | | | 1.23 | | | 1.27 |
| Transportation expenses | | | 0.75 | | | 0.90 | | | 0.90 | | | 0.91 | | | 0.70 |
| Depreciation, depletion and amortization | | | 3.05 | | | 3.51 | | | 5.16 | | | 5.62 | | | 7.58 |
| General and administrative expense(1) | | | 1.75 | | | 2.52 | | | 3.77 | | | 3.62 | | | 3.76 |
- (1)
- Net of amounts capitalized.
Comparison of Nine Months Ended September 30, 2007 to Nine Months Ended September 30, 2006
Oil and Natural Gas Revenues. Oil and natural gas revenues increased $13.3 million (31%) to $56.0 million for the nine months ended September 30, 2007 from $42.7 million for the same period in 2006. The increase was primarily due to a 29% increase in production, which is largely attributable to the acquisition of the Hastings Complex on March 31, 2006 and the onshore portion of the West Montalvo field on May 11, 2007.
Oil revenues increased by $12.0 million (31%) in the first nine months of 2007 to $50.5 million, compared to $38.5 million in the first nine months of 2006. Oil production rose 33%, with production of 846 MBbl in the first nine months of 2007 compared to 638 MBbl in the first nine months of 2006. Production increased approximately 25% as a result of the acquisition of and subsequent production improvements achieved from the Hastings Complex and the remaining 9% as a result of the acquisition of and subsequent production improvements achieved from the onshore portion of the West Montalvo field, partially offset by a 1% decline in production volumes from other properties. Our average realized price for oil decreased $0.60 (1%) to $59.71 per Bbl for the period.
Natural gas revenues increased $1.3 million (30%) in the first nine months of 2007 to $5.5 million compared to $4.2 million in the first nine months of 2006. Natural gas production increased 9%, with production of 820 MMcf compared to 751 MMcf in the first nine months of 2006. Production increased approximately 6% as a result of additional production from our non-operated interest in the Dos Cuadras field and approximately 3% as a result of the acquisition of and subsequent production improvements achieved from the onshore portion of the West Montalvo field. Our average realized price for natural gas increased $1.09 (19%) to $6.73 per Mcf for the period.
Pipeline Revenues. Pipeline revenue remained relatively flat at $5.7 million in the first nine months of 2007, compared to $5.8 million in the first nine months of 2006.
79
As a result of the foregoing factors, total revenues increased $13.3 million (27%) to $61.8 million in the first nine months of 2007, compared to $48.5 million in the first nine months of 2006.
Lease Operating Expenses. Lease operating expenses increased $5.2 million (30%) to $22.6 million in the first nine months of 2007 from $17.4 million in the first nine months of 2006. Lease operating expenses increase approximately 14% as a result of the acquisition of and subsequent production increases from the Hastings Complex and approximately 10% as a result of the acquisition of the onshore portion of the West Montalvo field acquired in May 2007, combined with a 6% increase in lease operating expenses related to other properties. The increase in lease operating expenses for other properties relates to an increase in the number of producing wells, normal variances of timing of lease operating expenses, including expenses relating to periodic maintenance projects which continued into the first half of 2007, and increased costs of third party services.
Production and Property Taxes. Production and property taxes increased $0.3 million (33%) to $1.2 million in the first nine months of 2007 from $0.9 million in the 2006 period. The increase was primarily due to the 31% increase in oil and natural gas revenue and the increase in the proportion of revenues generated in Texas where production tax rates are higher.
Transportation Expense. Transportation expense remained flat at $0.7 million for the first nine months of 2006 and 2007.
Pipeline Operating Expense. Pipeline operating expense decreased $0.3 million (15%) to $1.5 million in the first nine months of 2007 from $1.8 million in the 2006 period. The decrease was primarily due to the performance of periodic maintenance during the 2006 period.
Depletion, Depreciation and Amortization (DD&A). DD&A expense increased $3.1 million (73%) to $7.4 million in the first nine months of 2007 from $4.3 million in the first nine months of 2006. The increase was primarily due to higher depletion expense resulting from an increase in our oil and natural gas properties related to the Hastings and West Montalvo acquisitions and an increase in oil and natural gas property costs during the period relating to exploitation and development activities.
Accretion of Abandonment Liability. Accretion expense was $0.7 million in the first nine months of 2007 compared to $0.5 million in the first nine months of 2006. The increase was due primarily to accretion from the Hastings Complex acquired in March 2006 and the onshore portion of the West Montalvo field acquired in May 2007.
General and Administrative (G&A). G&A expenses increased $0.9 million (34%) to $3.7 million in the first nine months of 2007 from $2.8 million in the first nine months of 2006. The increase resulted primarily from additions to our professional staff and related infrastructure in connection with our Hastings Complex acquisition. Other significant increases in general and administrative expenses in the first nine months of 2007 relate to a $0.2 million non-recurring charge attributable to a settlement of an employment contract and a $0.3 million increase in non-cash SFAS 123R share-based compensation expense.
Financing Costs. Financing costs increased $2.7 million (70%) to $6.6 million in the first nine months of 2007 from $3.9 million in the first nine months of 2006. The change between periods was due to a $1.7 million increase in interest expense resulting from an increase in average debt outstanding during the 2007 period, and a $1.1 million loss on extinguishment of debt recognized in 2006 in connection with the refinancing of certain debt during the period, partially offset by a decrease in amortization of deferred loan costs.
Income Taxes. Income tax expense recorded in both the 2007 and 2006 periods results from the Texas Margin tax on the results of our operations in Texas.
80
Net Income. Net income for the first nine months of 2007 was $17.1 million compared to net income of $16.2 million for the same period in 2006. The change between periods is the result of the items discussed above.
Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005
Oil and Natural Gas Revenues. Oil and natural gas revenues increased $20.7 million (55%) to $58.6 million in 2006 from $37.9 million in 2005. The increase was primarily due to production attributable to the Hastings Complex acquisition and higher realized oil prices.
Oil revenues increased by $22.2 million in 2006 (74%) to $52.3 million compared to $30.1 million in 2005. Oil production rose 49%, with production of 905 MBbl in 2006 compared to 607 MBbl in 2005. The production increase was primarily attributable to the Hastings Complex acquisition. Our average realized price for oil increased $8.20 (17%) to $57.77 per Bbl for the period.
Natural gas revenues decreased $1.5 million in 2006 (20%) to $6.3 million compared to $7.8 million in 2005. Natural gas production decreased 7%, with production of 1,009 MMcf compared to 1,090 MMcf in 2005. The decrease was due to normal production declines in the Union Island field. Our average realized price for natural gas decreased $0.90 (13%) to $6.25 per Mcf for the period.
Pipeline Revenues. Pipeline revenue increased 22%, from $6.2 million in 2005 to $7.6 million in 2006. This increase was primarily due to revenues from the Union Island pipeline, which was acquired in the fourth quarter of 2005.
As a result of the foregoing factors, total revenues increased $22.1 million (50%) to $66.2 million in 2006, compared to $44.1 million in 2005.
Lease Operating Expenses. Lease operating expenses increased $9.7 million (68%) to $24.0 million in 2006 from $14.3 million in 2005. Lease operating expenses increased 71% as a result of the acquisition of and subsequent production increases from the Hastings Complex acquired in March 2006, partially offset by declines in lease operating expenses in other fields. A significant part of this increase was attributable to remedial work projects performed in the Hastings Complex in the second half of 2006.
Production and Property Taxes. Production and property taxes increased $1.1 million (304%) to $1.5 million in 2006 from $0.4 million in 2005. The increase was primarily due to the 54% increase in oil and natural gas revenue and the increase in the proportion of revenues generated in Texas where production tax rates are higher.
Transportation Expense. Transportation expense increased 37%, from $0.7 million in 2005 to $1.0 million in 2006. This was primarily attributable to volume increases.
Pipeline Operating Expense. Pipeline operating expense increased $0.7 million (45%) to $2.3 million in 2006 from $1.6 million in 2005. The increase was primarily due to operating expenses incurred on the Union Island pipeline, which was acquired in the fourth quarter of 2005.
Depletion, Depreciation and Amortization (DD&A). DD&A expense increased $2.8 million (100%) to $5.6 million in 2006 from $2.8 million in 2005. The increase was primarily due to a higher depletion expense resulting from the increase in the value of oil and natural gas properties obtained in the Hastings Complex acquisition and an increase in future development costs.
Accretion of Abandonment Liability. Accretion expense increased $0.1 million (14%) to $0.7 million in 2006 from $0.6 million in 2005. The increase was due to accretion from asset retirement obligations related to the Hastings Complex.
81
General and Administrative (G&A). G&A expenses increased $2.0 million (104%) to $4.0 million in 2006 from $2.0 million in 2005. The increase in G&A expense resulted primarily from increased compensation costs associated with increases in professional, technical and support staff and non-cash costs relating to FAS 123R recorded in 2006.
Financing Costs. Financing costs increased $5.4 million (1,800%) to $5.7 million in 2006 from $0.3 million in 2005. The change between periods was due to a $4.9 million increase in interest expense resulting from additional debt incurred in 2006 in connection with the acquisition of the Hastings Complex in March 2006, and a $0.5 million increase in amortization of deferred loan costs.
Income Taxes. Income tax expense recorded in 2006 results from the Texas Margin tax on the results of our operations in Texas. The Texas Margin tax became effective in 2006.
Net Income. Net income was $21.4 million for 2006 and 2005.
Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004
Oil and Natural Gas Revenues. Oil and natural gas revenues increased $10.7 million (39%) to $37.9 million for the year ended December 31, 2005 from $27.2 million for 2004. The increase was primarily attributable to rising oil and natural gas prices and an in increase in natural gas production.
Oil revenues increased by $7.4 million in 2005 (33%) to $30.1 million from $22.7 million in 2004. Oil production declined slightly with production of 607 MBbl in 2005 compared to 628 MBbl in 2004. Our average realized price for oil increased $13.45 (37%) to $49.57 per Bbl for 2005.
Natural gas revenues increased $3.3 million in 2005 (72%) to $7.8 million from $4.5 million in 2004. Natural gas production rose 43%, with production of 1,090 MMcf compared to 761 MMcf in 2004, primarily because of the acquisition of the Union Island field in December 2004. Our average realized price for natural gas increased $1.18 (20%) to $7.15 per Mcf for 2005.
Pipeline Revenues. Pipeline revenue decreased 3%, from $6.4 million in 2004 to $6.2 million in 2005. This decrease was primarily due to a reduction in volumes transported on the Ventura Pipeline in the 2005 period.
As a result of the foregoing factors, total revenues increased $10.4 million (31%) to $44.1 million in 2005, compared to $33.7 million in 2004.
Lease Operating Expenses. Lease operating expenses increased $2.0 million (16%) to $14.3 million in 2005 from $12.4 million in 2004. This increase was primarily due to additional lease operating expenses incurred as a result of the December 2004 acquisition of the Union Island field combined with unanticipated expenses associated with the resolution of mechanical problems at a well in the South Ellwood field.
Production and Property Taxes. Production and property taxes increased $0.1 million (39%) to $0.4 million in 2005 from $0.3 million in 2004. The increase was due to the corresponding 38% increase in oil and natural gas revenue in 2005.
Transportation Expense. Transportation expense increased by $0.1 million (25%) to $0.7 million in 2005 from $0.6 million in 2004 primarily due to volume increases in 2005.
Pipeline Operating Expense. Pipeline operating expense increased $0.2 million (12%) to $1.6 million in 2005 from $1.4 million in 2004. The increase was primarily due to operating expenses incurred on the Union Island pipeline, which was acquired in the fourth quarter of 2005.
Depletion, Depreciation and Amortization (DD&A). DD&A expense increased $0.5 (21%) to $2.8 million in 2005 from $2.3 million in 2004. This was due to higher depletion expense resulting from the increase in the value of oil and natural gas properties obtained in the Union Island acquisition and
82
changes in estimated future development costs and development costs incurred in 2005. DD&A expense also rose due to increased production volumes.
Accretion of Abandonment Liability. Accretion expense rose $0.1 million (22%) to $0.6 million in 2005 from $0.5 million in 2004. The increase was due to an increase in abandonment liability associated with the Union Island acquisition and additional wells.
General and Administrative (G&A). G&A expenses increased $0.7 million (50%) to $2.0 million in 2005 from $1.3 million in 2004. The largest single component of the increase was the accrual in December 2005 of a bonus pool paid to office and administrative staff, including officers, in the second quarter of 2006. This was due to the implementation of more structured and formalized plans relative to prior years, when bonus amounts were less predictable prior to the time of payment. The increase in G&A in 2005 also resulted from increases in technical staff and higher professional fees related to accounting and information technology systems conversions and enhancements.
Financing Costs. Financing costs decreased $0.7 million (73%) to $0.3 million in 2005 from $1.0 million in 2004. The change between periods was due to a $0.3 million decrease in interest expense resulting from lower average debt balances during 2005, and a $0.5 million loss on extinguishment of debt recognized in 2004 in connection with the refinancing of certain debt during the period, partially offset by an increase in amortization of deferred loan costs.
Net Income. Net income for 2005 was $21.4 million, compared to net income of $13.9 million in 2004. The change between periods is the result of the items discussed above.
Liquidity and Capital Resources
Our primary sources of liquidity are expected to be cash generated from our operations, amounts available under our new credit facility and funds from future private and public equity and debt offerings.
Cash Flows
| | Years Ended December 31,
| | Nine Months Ended September 30,
| |
---|
| | 2004
| | 2005
| | 2006
| | 2006
| | 2007
| |
---|
| | (In thousands)
| |
---|
Cash provided by operating activities | | $ | 16,900 | | $ | 24,036 | | $ | 27,009 | | $ | 21,634 | | $ | 26,740 | |
Cash used in investing activities | | | (5,687 | ) | | (6,953 | ) | | (48,474 | ) | | (62,163 | ) | | (63,497 | ) |
Cash provided by (used in) financing activities | | | (11,213 | ) | | (17,083 | ) | | 21,465 | | | 40,529 | | | 36,757 | |
Operating activities. Net cash provided by operating activities during the years ended December 31, 2004, 2005 and 2006 was $16.9 million, $24.0 million and $27.0 million, respectively. The increases were primarily due to increasing commodity prices and production from acquired properties. Net cash provided by operating activities during the nine months ended September 30, 2006 and 2007 was $21.6 million and $26.7 million, respectively. The change was due to increasing production partially offset by increasing production expenses from acquired properties.
Investing activities. Net cash used in investing activities during the years ended December 31, 2004, 2005 and 2006 was $5.7 million, $7.0 million and $48.5 million, respectively. During these periods, investing activities were comprised of additions to oil and natural gas assets, including our interest in the Union Island pipeline in 2004, the Union Island field in 2005 and the Hastings Complex in 2006. The acquisition costs were $4.6 million, $6.2 million and $39.0 million, respectively. In addition, capital expenditures for the development of our oil and natural gas assets and upgrades to our platform and surface facilities over the three-year period from 2004 to 2006 were $1.1 million, $0.7 million and
83
$9.5 million, respectively. Net cash used in investing activities during the nine months ended September 30, 2006 and 2007 was $62.2 million and $63.5 million, respectively. During these periods, investing activities were comprised of additions to oil and natural gas properties, including our interest in the Hastings Complex in the 2006 period and the onshore portion of the West Montalvo field in the 2007 period which were $57.7 million and $37.0 million, respectively. Capital expenditures for the development of our oil and natural gas assets over these periods were $4.4 million and $26.5 million, respectively.
Financing activities. Net cash used in financing activities during the years ended December 31, 2004 and 2005 was $11.2 million and $17.1 million, respectively, and net cash provided by financing activities was $21.5 million in the year ended December 31, 2006. Net cash used in financing activities in 2004 and 2005 represent the excess of operating cash flows over cash used for additions to oil and natural gas properties, including acquisitions. Net cash provided by financing activities in 2006 represents the additional funding required in excess of operating cash flow in that year for additions to oil and natural gas properties, including the acquisition of the Hastings Complex in March 2006. Net cash provided by financing activities during the nine months ended September 30, 2006 and 2007 was $40.5 million and $36.8 million, respectively. Net cash provided by financing activities in those periods represents the additional funding required in excess of operating cash flow in that period for additions to oil and natural gas properties, including the acquisitions of the Hastings Complex in March 2006 and the onshore portion of the West Montolvo field in May 2007.
Capital Resources and Requirements
Our partnership agreement requires that we distribute all of our available cash quarterly. In making cash distributions, our general partner will attempt to avoid large variations in the amount we distribute from quarter to quarter. In order to facilitate this, our partnership agreement will permit our general partner to establish cash reserves to be used to pay distributions for any one or more of the next four quarters. In addition, our partnership agreement allows our general partner to borrow funds to make distributions. For example, we may borrow to make distributions to unitholders in circumstances where we believe that the distribution level is sustainable over the long term, but short-term factors have caused available cash from operations to be insufficient to sustain our level of distributions. We may also borrow to make distributions to unitholders when we are required to pay a derivative counterparty the difference between the fixed price set forth in a derivative contract and the market price before we receive the proceeds from the sale of the hedged production. Because we will distribute all of our available cash, we will not have those amounts available to reinvest in our business to increase our asset base and as a result, we may not grow as quickly as other oil and natural gas businesses or at all.
We plan to reinvest a sufficient amount of our cash flow in acquisitions and exploitation and development projects in order to maintain our asset base, and we plan to use external financing sources as well as cash flow from operations and cash reserves to increase our asset base. Because our proved reserves and production are subject to natural declines, we will need to make acquisitions to sustain our level of distributions to unitholders over time. In estimating the minimum amount of Adjusted EBITDA that we must generate to pay our minimum quarterly distribution to the unitholders for each quarter for the twelve months ended March 31, 2009, we have assumed that we will incur capital expenditures of $15.7 million in order to allow us to maintain our asset base. We estimate that our total capital expenditures for the twelve months ending March 31, 2009 will be approximately $24.3 million. We expect to finance approximately $8.6 million of that amount from our new credit facility.
If cash flow from operations does not meet our expectations, we may reduce our expected level of capital expenditures, reduce distributions to unitholders, and/or fund a portion of our capital expenditures using borrowings under our new credit facility, issuances of debt and equity securities or
84
from other sources, such as asset sales. We cannot assure you that needed capital will be available on acceptable terms or at all. Our ability to raise funds through the incurrence of additional indebtedness could be limited by the covenants in our new credit facility. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.
Credit Facility
We plan to enter into a new credit facility in connection with the closing of the offering, under which we expect to have borrowings of $157.5 million at the closing of this offering ($117.5 million of which will be secured by marketable securities which we intend to purchase with a portion of the net proceeds of this offering).
We expect that our new credit facility will mature four years from the effective date, unless extended. We expect to be allowed to prepay all loans under our new credit facility in whole or in part from time to time without premium or penalty, subject to certain restrictions in our new credit facility. We anticipate that our obligations under our new credit facility will be secured by mortgages on our oil and natural gas properties as well as a pledge of all ownership interests in our operating subsidiaries. We anticipate that the obligations under our new credit facility will be guaranteed by all of our operating subsidiaries and may be guaranteed by any future subsidiaries.
We expect that our new credit facility will give us the ability to pay distributions to unitholders as long as there has not been a default of event of default. We expect our new credit facility will be available for general partnership purposes, including working capital, capital expenditures and distributions. We expect that the indebtedness under our new credit facility will bear interest at the prime rate or LIBOR plus an applicable margin, will contain various representation, warranties, covenants and indemnities customary for its type, including limitations on our ability to incur indebtedness, grant liens and make distributions and requirements that we maintain specified financial ratios. The foregoing description is not complete and is qualified in its entirety by the terms and conditions of the credit agreement evidencing our new credit facility.
Contractual Obligations
We intend to enter into an administrative services agreement with Venoco and certain of its affiliates pursuant to which Venoco will operate substantially all of our assets and perform administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering. Under the administrative services agreement, we will reimburse Venoco for its costs in providing services to us as well as for all direct and indirect expenses incurred by Venoco and it's affiliates on our behalf.
The following table provides the aggregate amounts of our estimated contractually obligated payment commitments as of September 30, 2007 (in thousands):
| | Payments Due by Period
|
---|
| | Less than One Year
| | 1 to 3 Years
| | 3 to 5 Years
| | After 5 years
| | Total
|
---|
Contractual obligations and commitments | | | | | | | | | | | | | | | |
Credit facility | | $ | — | | $ | 1,927 | | $ | — | | $ | — | | $ | 1,927 |
Term debt | | | — | | | — | | | — | | | 81,214 | | | 81,214 |
| |
| |
| |
| |
| |
|
Total | | $ | — | | $ | 1,927 | | $ | — | | $ | 81,214 | | $ | 83,141 |
| |
| |
| |
| |
| |
|
The debt amounts included in the table above are based on an allocation of Venoco's historical debt; however, Venoco does not intend to transfer any of its historical debt to us. As discussed in more
85
detail above, in connection with the closing of the offering, we plan to enter into a new credit facility, which we expect will have a maturity date four years from the effective date.
Amounts related to interest expense on our debt instruments are not included in the table above because the interest rates on those debt instruments are variable. During the years ended December 31, 2004, 2005 and 2006, we incurred interest expense on our debt instruments of $0.4 million, $0.1 million and $5.0 million, respectively. During the nine months ended September 30, 2006 and 2007 we incurred interest expense on our debt instruments of $3.4 million and $5.1 million, respectively.
Amounts related to our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total amount of asset retirement obligations at September 30, 2007 is $11.4 million.
Off-Balance Sheet Arrangements
As of September 30, 2007, we did not have any off-balance sheet arrangements. We may periodically enter into operating leases for compressors and other items such as lease and well equipment. As described above, we also intend to enter into a new credit facility in connection with the completion of this offering. In accordance with GAAP, there is no carrying value recorded for operating leases or for a credit facility until we borrow from the facility. In the future, we may use off-balance sheet arrangements such as undrawn credit facility commitments, including letters of credit, operating lease agreements or purchase commitments to finance portions of our capital and operating needs.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based upon financial statements that have been prepared in accordance with accounting principles generally accepted in the United States, or GAAP. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We have identified certain accounting policies as being of particular importance to the presentation of our financial position and results of operations and which require the application of significant judgment by our management. We analyze our estimates, including those related to oil and natural gas revenues, oil and natural gas properties, fair value of derivative instruments, income taxes and contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies and estimates affect our more significant judgments and estimates used in the preparation of our financial statements.
Reserve Estimates
Our estimates of oil and natural gas reserves are, by necessity, projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as in the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulation of oil and natural gas that is difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and natural gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies and assumptions governing future oil and natural gas prices, future operating costs, severance, property and excise taxes, development costs and workover and remedial costs, all of which may vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on the
86
likelihood of recovery and estimates of the future net cash flows expected from them may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value and the rate of depletion of the oil and natural gas properties. For example, oil and natural gas price changes affect the estimated economic lives of oil and natural gas properties and therefore cause reserve revisions. Our December 31, 2006 estimate of net proved oil and natural gas reserves totaled 16,690 MBoe. Had oil and natural gas prices been 10% lower as of the date of the estimate, our total oil and natural gas reserves would have been approximately 2% lower. In addition, our proved reserves are concentrated in a relatively small number of wells. At December 31, 2006, excluding wells at Hastings and Dos Cuadras, which are reported as units rather than individual wells, 26% of our proved reserves were concentrated in our twelve largest wells. As a result, any changes in proved reserves attributable to such individual wells could have a significant effect on our total reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.
Oil and Natural Gas Properties, Depletion and Full Cost Ceiling Test
We follow the full cost method of accounting for oil and natural gas properties. Under this method, all productive and nonproductive costs incurred in connection with the acquisition of, exploration for and exploitation and development of oil and natural gas reserves are capitalized. Such capitalized costs include costs associated with lease acquisition, geological and geophysical work, delay rentals, drilling, completing and equipping oil and natural gas wells, and salaries, benefits and other internal salary related costs directly attributable to these activities. Proceeds from the disposition of oil and natural gas properties are generally accounted for as a reduction in capitalized costs, with no gain or loss recognized. Depletion of the capitalized costs of oil and natural gas properties, including estimated future development and capitalized asset retirement costs, is provided for using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. The capitalized costs are amortized over the life of the reserves associated with the assets, with the amortization being expensed as depletion in the period that the reserves are produced. This depletion expense is calculated by dividing the period's production volumes by the estimated volume of reserves associated with the investment and multiplying the calculated percentage by the capitalized investment. Changes in our reserve estimates will therefore result in changes in our depletion expense per unit. For example, a 10% reduction in our estimated reserves as of December 31, 2006 would have resulted in an increase of approximately $0.56 per Boe in our depletion expense rate during 2006. Costs associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and natural gas properties. Unproved property costs not subject to amortization consist primarily of leasehold and seismic costs related to unproved areas. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves established or impairment determined. We will continue to evaluate these properties and costs will be transferred into the amortization base as undeveloped areas are tested. Unproved oil and natural gas properties are not amortized, but are assessed for impairment either individually or on an aggregated basis using a comparison of the carrying values of the unproved properties to net future cash flows.
Capitalized costs of oil and natural gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%. Application of the ceiling test generally requires pricing future revenue at the unescalated prices in effect as of the last day of the relevant quarter, including the effects of cash flow hedges, and requires a write down for accounting purposes if the ceiling is exceeded. At December 31, 2006, our net capitalized costs did not exceed the ceiling.
Asset Retirement Obligations
Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations ("SFAS 143"). SFAS 143 provides that, if the fair value for
87
asset retirement obligations can be reasonably estimated, the liability should be recognized in the period when it is incurred. Oil and natural gas producing companies incur this liability upon acquiring or drilling a well. Under the method prescribed by SFAS No. 143, the retirement obligation is recorded as a liability at its estimated present value at the asset's inception, with the offsetting charge to property cost. Periodic accretion of discount of the estimated liability is recorded in the income statement. Prior to adoption of SFAS No. 143, we accrued for future abandonment costs of wells and related facilities through our depreciation calculation in accordance with Regulation S-X Rule 4-10 and industry practice. This method resulted in recognition of the obligation over the life of the property on a unit-of-production basis, with the estimated obligation netted in property cost as part of the accumulated depreciation, depletion and amortization balance.
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our properties at the end of their productive lives, in accordance with applicable laws. We have determined our asset retirement obligation by calculating the present value of estimated cash flows related to each liability. The discount rates used to calculate the present value varied depending on the estimated timing of the relevant obligation, but typically ranged between 5% and 9%. We periodically review the estimate of costs to plug, abandon and remediate our properties at the end of their productive lives. This includes a review of both the estimated costs and the expected timing to incur such costs. We believe most of these costs can be estimated with reasonable certainty based upon existing laws and regulatory requirements and based upon wells and facilities currently in place. Any changes in regulatory requirements, which changes cannot be predicted with reasonable certainty, could result in material changes in such costs. Changes in reserve estimates and the economic life of oil and natural gas properties could affect the timing of such costs and accordingly the present value of such costs.
Recent Accounting Pronouncements
In February 2007, the FASB issued SFAS 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 ("SFAS 159"), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected would be reported as a cumulative adjustment to beginning retained earnings. If we elect the Fair Value Option for certain financial assets and liabilities, we will report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. We are currently assessing the impact, if any, that the adoption of this pronouncement will have on our operating results, financial position and cash flows.
In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements ("SFAS No. 157"). SFAS 157 establishes a single authoritative definition of fair value, sets out a framework for measuring fair value and requires additional disclosures about fair value measurements. The standard requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy. SFAS 157 does not require any new fair value measurements, but will remove inconsistencies in fair value measurements between various accounting pronouncements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The adoption of SFAS 157 is not expected to have a material impact on our consolidated financial position or results of operations. However, additional disclosures may be required about the information used to develop the measurements.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108, "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements" ("SAB 108"). SAB 108 provides interpretive guidance on how the effects of the carryover or reversal of
88
prior year misstatements should be considered in quantifying a current year misstatement. The staff of the SEC believes that registrants should quantify errors using both a balance sheet and an income statement approach and evaluate whether either approach results in quantifying a misstatement that, when all relevant quantitative and qualitative factors are considered, is material. SAB 108 is effective for the first annual period ending after November 15, 2006 and provides for a one-time transitional cumulative effect adjustment to beginning retained earnings as of January 1, 2006 for errors that were not previously deemed material but are deemed material under the guidance in SAB 108. The adoption of SAB 108 did not have a material impact on our consolidated financial position or results of operations.
Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term "market risk" refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposure. All of our market risk sensitive instruments will be entered into for purposes other than speculation.
This disclosure provides information about hedging arrangements we plan to use to manage commodity price volatility. Due to the historical volatility of oil and natural gas prices, we plan to implement a hedging strategy aimed at reducing the variability of the prices we receive for our production and providing a minimum revenue stream. We intend enter into derivative transactions such as collars, fixed price swaps and puts in order to hedge our exposure to changes in commodity prices. All contracts will be settled with cash and will not require the delivery of a physical quantity to satisfy settlement. While this hedging strategy may result in us having lower revenues than we would have if we were unhedged in times of rising oil and natural gas prices, we believe that the stabilization of prices and protection afforded us by providing a revenue floor on a portion of our production will be beneficial.
We may borrow under fixed rate and variable rate debt instruments that give rise to interest rate risk. Our objective in borrowing under fixed rate or variable rate is to satisfy capital requirements while minimizing our costs of capital.
As part of our business strategy, we intend to enter into hedging arrangements in the future with respect to at least 70% of the expected production from our proved developed producing reserves over a three- to five-year period in order to reduce our exposure to fluctuations in the prices of oil and natural gas.
Our hedging arrangements will be designed to remove a significant portion of price volatility associated with our future oil and natural gas production. Our hedging arrangements will not eliminate the effects of changing oil and natural gas prices on our cash flows from operations for those periods.
89
BUSINESS
Overview
We are a growth-oriented Delaware limited partnership formed on September 25, 2007 by Venoco (NYSE: VQ) to acquire, exploit, develop and produce oil and natural gas properties. Our assets consist primarily of producing oil and natural gas properties and are principally located in coastal California and onshore Texas. Most of our oil and natural gas properties are located in large, mature fields with well-known geologic characteristics and long production histories. Our properties generally have stable and predictable production profiles and long reserve lives.
As of December 31, 2006, the Partnership Properties had estimated proved reserves of 21.2 MMBoe, of which 86.2% were oil and 81.1% were classified as proved developed, and had a reserve-to-production ratio of 15.1 years. As of September 30, 2007, the Partnership Properties consisted primarily of working interests in 325 gross producing wells, with a 38.5% average working interest. We operate interests that accounted for 80.8% of our pro forma production for the nine months ended September 30, 2007. The Partnership Properties represented 21.5% of Venoco's estimated proved reserves as of December 31, 2006, including reserves attributable to properties acquired by Venoco after that date. The Partnership Properties also include five associated oil or natural gas pipeline systems.
The following table summarizes information about our oil and natural gas properties by region:
| | Estimated Pro Forma Proved Reserves as of December 31, 2006
| | Pro Forma Average Daily Net Production for the Nine Months Ended September 30, 2007 (Boe/d)(1)
| |
| |
| |
---|
| |
| | Estimated Production Decline Rate(3)
| |
---|
Region
| | Total (MMBoe)
| | % Developed
| | % Oil
| | Pro Forma Reserve-to- Production Ratio (Years)(2)
| |
---|
California | | | | | | | | | | | | | |
| Coastal(4) | | 12.9 | | 70.9 | % | 88.0 | % | 2,346 | | 15.1 | | 8.2 | % |
| Other | | 1.4 | | 85.2 | % | — | | 239 | | 15.5 | | 9.2 | % |
Texas | | 6.9 | | 99.4 | % | 100.0 | % | 1,260 | | 15.0 | | 4.7 | % |
| |
| | | | | |
| | | | | |
Total | | 21.2 | | 81.1 | % | 86.2 | % | 3,845 | | 15.1 | | 7.2 | % |
| |
| | | | | |
| | | | | |
- (1)
- Production data for coastal California includes the results of the onshore portion of the West Montalvo field acquired by Venoco on May 11, 2007, as if the transaction had occurred on January 1, 2007.
- (2)
- The pro forma reserve-to-production ratio is calculated by dividing estimated pro forma proved reserves as of December 31, 2006 by the annualized pro forma average daily net production for the nine months ended September 30, 2007.
- (3)
- Represents the percentage decrease in annual production from the proved developed producing reserves of the Partnership Properties in 2009 when compared to 2008, as estimated in our Reserve Reports.
- (4)
- Includes onshore and offshore properties in southern California.
Our Relationship with Venoco, Inc.
One of our principal strengths is our relationship with Venoco, a publicly traded independent energy company primarily engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties in California and Texas. Venoco's pro forma estimated proved reserves as of December 31, 2006, including reserves attributable to properties acquired after that date and the Partnership Properties, were 98.6 MMBoe, of which 58.2% were oil and 57.9% were classified as proved developed. Venoco's average daily net production was 19,344 Boe/d for the nine months ended September 30, 2007.
90
Since its inception, Venoco has sought to acquire mature producing properties characterized by long reserve lives, well-established production histories, and predictable production profiles that exhibit relatively moderate production declines. Venoco has an established track record of successfully acquiring, owning and operating oil and natural gas properties located in California and Texas, our primary areas of operation.
Most of Venoco's oil and natural gas properties are located in fields with significant remaining accumulations of hydrocarbon in place covering multiple geologic horizons. Fields of this type often have a significant number of potential drilling prospects, providing Venoco with the opportunity to not only pursue identified exploitation and development opportunities, but also to add incremental reserves over time as advances in technology lead to improved extraction techniques and enhanced field recovery rates. Following its contribution of the Partnership Properties to us, Venoco will continue to own and operate oil and natural gas properties with exploitation and development opportunities that are, or after additional capital is invested may become, suitable for us. These properties include, among others, Venoco's significant remaining working interests in the South Ellwood field and in the Hastings Complex, two of the largest Partnership Properties.
Venoco views us as an integral part of its growth strategy, and we believe that it will be strongly incentivized to contribute or sell additional assets to us and to pursue acquisitions jointly with us in the future. In addition to complementary business strategies and the proximity of our respective properties, Venoco will own a significant interest in us following the closing of this offering, including a 55.4% limited partner interest, as well as our general partner and all of our incentive distribution rights. However, we cannot say which assets, if any, Venoco may make available to us, or if we will pursue the opportunity to acquire those assets if they are made available to us. Furthermore, Venoco regularly evaluates acquisitions and dispositions and may elect to acquire or dispose of properties in the future without offering us the opportunity to participate in those transactions. Venoco has retained this flexibility because it believes that doing so is in the best interests of its stockholders. Moreover, after this offering, Venoco will continue to be free to act in a manner that is beneficial to its interests and detrimental to ours, which may include electing not to present us with future acquisition opportunities. Accordingly, while our relationship with Venoco and its subsidiaries is a significant strength, it also is a source of potential conflicts. Please read "Conflicts of Interest and Fiduciary Duties."
Business Strategy
Our primary business objectives are to generate stable cash flows that allow us to make quarterly cash distributions to our unitholders and to increase those distributions over time by executing the following business strategies:
Make accretive acquisitions of producing properties with long-lived, stable and predictable production profiles. We seek to acquire properties that possess the following characteristics in transactions that are accretive to our cash flow per unit:
- •
- predictable production profiles;
- •
- long reserve lives;
- •
- generally moderate production decline rates; and
- •
- relatively low-risk reserve development and exploitation potential.
In addition to acquisitions of producing oil and natural gas properties made directly from unaffiliated third parties, we expect to have the opportunity to make future acquisitions of producing oil and natural gas properties directly from Venoco or from unaffiliated third parties in partnership with Venoco. If we purchase assets directly from Venoco, we believe that we will do so in negotiated transactions and not through an auction process. Although Venoco is under no obligation to contribute
91
or sell to us any of its retained properties or to jointly pursue acquisition opportunities with us, we believe Venoco will be strongly incentivized to do so given its significant ownership interest in us.
Increase our proved reserves and production through relatively low-risk exploitation and development activities. We plan to complement our acquisition efforts with growth through relatively low-risk and cost-effective exploitation and development activities. In addition to maintenance capital expenditures, we currently estimate that we will spend approximately $8.6 million during the twelve months ending March 31, 2009 on our existing properties, including development wells and recompletion, stimulation and workover activities.
Reduce the volatility in our cash flow through our commodity hedging activities. We intend to enter into hedging arrangements for at least 70% of our estimated production from proved developed producing reserves for a period of three to five years, as appropriate, in order to mitigate our exposure to changes in commodity prices. Our hedging arrangements will be designed to remove a significant portion of price volatility associated with our future oil and natural gas production. Our hedging arrangements will not eliminate the effects of changing oil and natural gas prices on our cash flow from operations. Please read "Management's Discussion and Analysis and Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk."
Competitive Strengths
We believe the following competitive strengths will enable us to achieve our primary business objectives and to successfully execute our strategies:
- •
- Our Relationship with Venoco. Our relationship with Venoco provides us with a number of competitive advantages, including:
- —
- the opportunity to acquire attractive assets directly from Venoco or jointly with Venoco in situations that either of us individually would not be able to pursue on our own; and
- —
- access to Venoco's substantial operating, technical and other expertise, including its staff of over 40 engineers and geoscientists, to assist us with the execution of our business strategy.
- •
- Our Experienced Management Team. Our management team has an established track record of successfully acquiring, exploiting and developing oil and natural gas properties. The members of our management team have an average of over 20 years of experience in the oil and natural gas industry, and have led both public and private oil and natural gas companies. Since January 2005, our management team has successfully completed 16 acquisitions for Venoco, consisting of estimated proved reserves of approximately 46.1 MMBoe.
- •
- Long-Lived Reserves with Stable and Predictable Production Profiles. Our oil and natural gas properties generally have stable and predictable production profiles with relatively moderate production declines, long reserve lives and well-established production histories. Collectively, our properties had an estimated production decline rate of 7.2% at December 31, 2006.
- •
- Geographicly Diversified Assets in Established, Mature Producing Basins. We own and operate oil and natural gas assets in both California and Texas, two of the three largest oil producing states in the United States and two of the ten largest natural gas producing states, according to the U.S. Energy Information Administration ("EIA"). By operating in diverse areas, we are able to mitigate our exposure to adverse developments in any one area. In addition, operations in mature basins with long production histories are typically less subject to certain risks than operations in undeveloped or unexplored basins.
- •
- Operating Control. We operate interests that accounted for 80.8% of our pro forma production for the nine months ended September 30, 2007. Maintaining control of our properties allows us
92
Properties
Overview
Our properties are principally oil fields located in coastal California and onshore Texas. Our offshore California properties are located in the Santa Barbara channel in southern California and consist of the South Ellwood field and the Dos Cuadras field. Our onshore California fields include the West Montalvo field, the Beverly Hills West field, and the Santa Clara Avenue field. In addition to these fields, we own working interests in the Union Island natural gas field in the Sacramento Basin in northern California. Our remaining estimated proved reserves are located in the Hastings Complex in Brazoria County south of Houston, Texas. We also own several pipelines that transport oil or natural gas for Venoco and third parties.
Coastal California
Coastal California is characterized by large, long-lived oil fields. Our offshore California fields are located in the Santa Barbara-Ventura basin. Oil has been produced from a number of geologic formations in this prolific basin for over 100 years. Our onshore coastal California fields are located in the Los Angeles and Ventura basins, which have also been producing oil and natural gas for over 100 years.
South Ellwood Field. We have a 23% working interest in certain producing wells (also referred to as wellbore assignments) in the South Ellwood field. We also have the right to participate in additional wells, which, together with our 23% working interest, represented 3.8 MMBoe, or 18.1%, of our estimated proved reserves as of December 31, 2006 and 618 Boe/d of our average net production in 2006. In addition, we have the right to participate in additional wells that may be drilled within the area covering the current boundaries of Venoco's interest in the field. The field, which is located in California's state waters approximately two miles offshore southern California in the Santa Barbara Channel, is approximately seven miles long and is part of a regional east-west trend of similar geologic structures running along the northern flank of the Santa Barbara Channel and extending to the Ventura basin. The field was placed into production in 1966 and produces primarily from the Monterey formation. Venoco owns the remaining interest in the field and is the operator. We estimate that our capital expenditures in the South Ellwood field will be approximately $1.8 million during the twelve months ending March 31, 2009 for upgrades and maintenance of platform and plant facilities.
Oil production from the South Ellwood field is transported from platform Holly by pipeline to Venoco's onshore facility for processing. The oil is then transported to a marine terminal via a common carrier pipeline. From the marine terminal, the oil is transported by barge. At this time, the barge is the only means available for delivery of oil from the marine terminal. The barge is owned and operated by a third party with whom Venoco has a long-term service contract. Please read "Risk Factors—Risks Related to Our Business." We anticipate that the barge will occasionally be unavailable due to inclement weather, maintenance or other planned or unplanned downtime. A number of measures have been taken to mitigate this risk. For example, an alternate barge is being fitted for auxiliary service and Venoco has initiated field development activities that include installing a new pipeline. The alternate barge and construction of the new pipeline, however, are subject to permitting and other regulatory requirements. Venoco also currently sells the oil production from the South Ellwood field to one purchaser. If the current purchaser were unwilling to accept further deliveries from the barge, then Venoco would have to find a new purchaser and/or enter into an alternative delivery arrangement for the production. In order to mitigate this risk, we have obtained access to an alternate berth to receive
93
the barge at the point of delivery. This alternate berth will enable us to potentially sell production from the South Ellwood field to a number of different refiners or into the spot market.
Venoco is seeking a lease extension in the South Ellwood field that would, if granted, significantly extend the area covered by its leases and would be developed from platform Holly. We would not have any interest in the lease extension area or any right to participate in operations conducted there. Venoco would not be permitted to use the wells in which we have an interest to develop the lease extension area, and we would not bear any of the direct costs of drilling wells into the lease extension area. We will be obligated to bear some of the costs of facility upgrades necessary in connection with the development of the lease extension as reasonably allocated by Venoco based on estimates of the benefit we would receive from those upgrades in the form of lower per unit operating costs.
Dos Cuadras Field. Our 25% working interest in the Dos Cuadras field represented 3.0 MMBoe, or 14.0%, of our estimated proved reserves as of December 31, 2006 and 730 Boe/d of our average net production in 2006. The three-platform Dos Cuadras field, which is located in federal waters approximately five miles offshore in the Santa Barbara Channel, is operated by an unaffiliated third party. Production from the field is transported by pipeline to Los Angeles, California. We also have working interests ranging from approximately 17.5% to 25% in the associated onshore facility and pipelines. We estimate our capital expenditures in the Dos Cuadras field will be $2.5 million during the twelve months ending March 31, 2009, which will primarily be used for workovers, recompletions, and waterflood enhancement.
West Montalvo Field. Our 100% working interest in the onshore portion of the West Montalvo field represented 4.5 MMBoe, or 21.3%, of our estimated proved reserves as of December 31, 2006 and 477 Boe/d of our average net production in 2006. The West Montalvo field, which is located in Ventura County, California, was acquired by Venoco in May 2007. Venoco will retain the offshore portion of the West Montalvo field. The field's existing reserves, which are produced from the Sespe formation, have a shallow decline rate as evidenced by a reserve-to-production ratio of approximately 27 years and an estimated production decline rate of 6.9%. In addition, we believe this field provides significant development opportunities. Our total capital expenditures for 2007 was $17.3 million. Our activities in 2007 were primarily focused on returning idle wells to production, working over and recompleting existing wells, and upgrading well lift systems and processing facilities. During the twelve months ending March 31, 2009 we estimate our capital expenditures for the onshore portion of the field will be approximately $7.8 million. Our 2008 capital program includes the drilling of one to two onshore infill development wells, the continuation of the field reactivation program, including workovers, recompletions and facilities upgrades, as well as commissioning a seismic survey for the field. The seismic survey will assist us in designing and optimizing a significant infill development drilling program.
Beverly Hills West Field. Our 100% working interest in the Beverly Hills West field represented 1.2 MMBoe, or 5.5%, of our estimated proved reserves as of December 31, 2006 and 392 Boe/d of our average net production in 2006. The Beverly Hills West field is located in Beverly Hills, California. This property is the subject of pending litigation for which Venoco has agreed to indemnify us for claims arising prior to the closing of this offering. Please read "Certain Relationships and Related Party Transactions—Agreements Relating to Our Operations—Omnibus Agreement."
Santa Clara Avenue Field. The Santa Clara Avenue field represented 0.5 MMBoe, or 2.3%, of our estimated proved reserves of as of December 31, 2006 and 160 Boe/d of our average net production in 2006. We have working interests in various leases in the field ranging from 43% to 100%. The Santa Clara Avenue field is located in Ventura County, California.
94
Other California
Union Island Field. We own a 50% working interest in the Union Island field, which is located in California's Sacramento Basin. In terms of historical production, the Sacramento Basin is one of California's most prolific onshore natural gas producing areas not associated with oil production, containing nine of the state's ten largest natural gas fields by that measure. It is located near northern California natural gas markets and has substantial natural gas gathering infrastructure and pipeline capacity. It is approximately 210 miles long and 60 miles wide and contains a variety of different geologic plays.
Production at the Union Island field is from the Winters interval found at a depth of approximately 9,500 feet. The field represented 1.4 MMBoe, or 6.4%, of our estimated proved reserves of as of December 31, 2006 and 246 Boe/d of our average net production in 2006. Natural gas produced from the field flows through the Union Island Pipeline to refineries in the San Francisco Bay Area.
Texas
Hastings Complex. We own a 44% working interest in the Hastings Complex, which is located approximately 30 miles south of Houston in Brazoria County. Venoco owns an additional 44% working interest in the complex and is the operator. In addition, Venoco owns a 100% interest in certain deeper, and currently non-producing, zones in the complex in which we do not have an interest. The Hastings Complex represented 6.9 MMBoe, or 32.5%, of our estimated proved reserves as of December 31, 2006 and 1,014 Boe/d of our average net production in 2006.
The Hastings Complex is comprised of the West Hastings Unit, the East Hastings field and the Hastings field. The complex produces from multiple Miocene and Frio reservoirs at depths ranging from 2,000 to 6,100 feet. The Hastings Complex has an estimated production decline rate of approximately 4.7% and a reserve-to-production ratio of approximately 15 years.
Venoco acquired the Hastings Complex in March 2006 and initiated an aggressive field reactivation program that included returning idle wells to production, increasing the lift capacity of existing wells, working over and recompleting existing wells, significantly upgrading surface facility fluid handling capacity and increasing water injection capabilities. With the majority of the reactivation program now completed, capital expenditures in the complex are expected to decline significantly in 2008. We currently estimate capital expenditures in the complex during the twelve months ending March 31, 2009 will be approximately $10.5 million and that our efforts will be primarily focused on installing more efficient lift systems on existing wells.
In November 2006, Venoco entered into an option agreement with a subsidiary of Denbury Resources, Inc. ("Denbury") relating to a potential CO2 enhanced recovery project in the Hastings Complex. Pursuant to the agreement, Denbury has an option to acquire substantially all of our and Venoco's interests in the complex and certain related property for use in an enhanced recovery project. Except as described below, we will participate in the transaction on the same terms as Venoco. Denbury may not exercise the option until September 2008. The initial exercise period will end in October 2009, subject to Denbury's right to extend it for successive one-year periods until 2016 for an annual extension fee. The extension fee will be payable only to Venoco, as will certain additional option payments Denbury has agreed to pay to Venoco. We will not receive any portion of any extension fee or additional option payments.
If Denbury exercises its option, then it will either purchase the properties for cash or, if Venoco so elects, enter into a volumetric production payment or similar arrangement with Venoco and us with respect to the properties. The purchase price or volumetric production payment will be based on the value of the properties as determined with respect to the net proved reserves associated with the
95
properties based on then-existing operations and NYMEX forward strip pricing, subject to certain adjustments. Contemporaneously with its exercise of the option, Denbury will commit to a development plan for the properties. Venoco will retain an overriding royalty interest in the CO2 project and will have a right to back into a working interest in the project after certain financial thresholds are met. We will not have any royalty or working interest in the CO2 project.
If we enter into a volumetric production payment or similar arrangement with Denbury, we would expect to use the payments we receive to fund capital expenditures, pay debt service and operating expenses and make distributions to our unitholders, as we will with other sources of operating income. If Denbury purchases our interests for a lump sum payment pursuant to the option agreement, we expect to use the proceeds of that transaction to acquire additional producing properties, as well as for other partnership purposes. In that circumstance, Venoco may offer to sell to us additional properties with reserve and production levels comparable to those associated with the interests sold to Denbury. Venoco would not be obligated to do so, however, and it may not be possible for us to acquire comparable properties from unaffiliated third parties on acceptable terms. Finally, there can be no assurance that Denbury will exercise its option.
Enhanced Oil Recovery Projects
Some of our properties may be suitable for enhanced oil recovery, or EOR, projects. EOR projects may involve, among other things, immiscible gas injection, microbial injection, CO2, LPG or other miscible gas injection, polymer flooding, high pressure air injection, chemical flooding, hydrocarbon solvent slug injection, amphipathic slug injection, surfactant flooding, in-situ combustion, steam injection, thermal recovery techniques, or other similar operations designed to increase the amount of oil recoverable from the Partnership Properties. Except as otherwise agreed, Venoco will bear 100% of the cost of any EOR project and will receive 100% of the proceeds of sale of the incremental production from any well or other asset with respect to which an EOR project is performed. Venoco will have the exclusive right to conduct EOR projects on each of the Partnership Properties other than the Beverly Hills West field, where an EOR project is currently underway. Venoco will also have the right to use (i) all personal property associated with those Partnership Properties, (ii) all rights to use the surface of those Partnership Properties and (iii) as much water from those Partnership Properties as may be reasonably necessary to conduct the EOR projects. The recovery method used, the Partnership Properties involved, and the extent and duration of such operations shall be determined by Venoco in its sole discretion.
Prior to exercising its right to conduct an EOR project, Venoco will enter into an agreement with us that will obligate Venoco to compensate us for lost production and reserves and any other interruption to our operations resulting from its exercise of its EOR right. The definitive terms of any agreement with Venoco relating to an EOR project would be subject to the approval of the conflicts committee of our general partner. However, we have agreed that we will not reject any EOR project proposal made by Venoco that the conflicts committee determines in good faith to be favorable to us, taking into account all of the terms of the proposal. Although the terms of any such agreement would be based on the relevant facts in existence at the time, we could, for example, enter into an arrangement in which Venoco would commit to provide us with royalty and/or working interests that would allow us to benefit from either the production and reserves associated with the EOR project or the production and reserves associated with different property expected to produce a stream of production that corresponds to the expected production we would forgo as a result of the EOR project, as determined with reference to an agreed forecast based on then-current operations. Venoco has agreed not to take any action with respect to an EOR project that would materially interfere with our operations until the third anniversary of the closing of this offering; this limitation, however, will not apply to projects in the Hastings Complex and will not prevent Venoco from conducting field studies, pilot programs or similar activities on any of the Partnership Properties.
96
Pipelines
Ellwood Pipeline, Inc. Ellwood Pipeline, Inc., our wholly owned subsidiary, owns three regulated oil pipelines and one unregulated natural gas pipeline:
- •
- the Ventura Pipeline System, a 14-mile oil pipeline that extends from Rincon Station in Ventura County, California to two other connecting pipeline carriers in Ventura County, California. The pipeline system has an operating capacity of 170,000 Bbl/d, and transports oil for Venoco and other third parties. Venoco's production represents approximately 52% of monthly volume on average. Volumes on the pipeline are shipped pursuant to a public tariff.
- •
- the Carpinteria Oil Pipeline System, a 23-mile oil pipeline that extends from Platform Grace in the Santa Barbara Channel to Rincon Station in Ventura County, California where it connects to the Ventura Pipeline System. The pipeline system has an operating capacity of 24,000 Bbl/d, and transports oil for Venoco and other third parties. Venoco's production represents approximately 80% of monthly volume on average. Volumes on the pipeline are shipped pursuant to a public tariff.
- •
- the Carpinteria Natural Gas Pipeline System, a 10-mile natural gas pipeline that extends from Platform Grace in the Santa Barbara Channel to Venoco's Carpinteria, California onshore facility where it connects to a public utility natural gas system. The pipeline system has an operating capacity of 20,000 MMBtu/d, and transports oil for Venoco and other third parties. No natural gas is currently flowing through this pipeline. Volumes on the pipeline are shipped under contractual agreements.
- •
- Line 96, a 3-mile oil pipeline that extends from Venoco's Ellwood onshore processing facility in Goleta, California to Venoco's Ellwood Marine Terminal in Goleta. The pipeline system has an operating capacity of 24,000 Bbl/d, and transports oil for Venoco and other third parties. Venoco's production represents approximately 83.3% of monthly volume on average. Volumes on the pipeline are shipped pursuant to a public tariff.
- •
- Rincon/Bush Island Line, an approximately one-mile long oil common carrier pipeline from Rincon/Bush Island in Ventura County, California to the Rincon Pipeline facility in Ventura County. The Rincon/Bush Island Line is regulated by the CPUC.
Whittier Pipeline Corporation. Whittier Pipeline Corporation, our wholly owned subsidiary, owns a gas processing plant and an unregulated crude oil pipeline at the Beverly Hills West field and a gas processing plant and an unregulated crude oil line at the Santa Clara Avenue field.
The Beverly Hills facilities consist of a gas processing plant located at the Beverly Hills West drill site in Los Angeles County, California and a six inch crude gathering line approximately 3,240 feet in length that extends from the Beverly Hills West field to Pico Boulevard to its point of connection with the Four Corners Pipe Line. The pipeline system has a maximum operating capacity of approximately 80,000 Bbl/d and transports oil exclusively for Venoco. Whittier Pipeline Corporation receives a portion of natural gas and natural gas liquid sales for processing and transporting.
The Santa Clara Avenue facilities consist of a gas processing plant located at the Site B Drill Site in the Santa Clara Avenue field in Ventura County, California and a six-inch crude gathering line approximately 4.19 miles in length that extends from the field at the intersection of Friedrich Road and Santa Clara Avenue with an ending near the northwesterly bank of the Santa Clara River where it connects to a third party eight inch line. The pipeline has a maximum operating capacity of approximately 27,900 Bbl/d and transports oil for the working interest owners in the Santa Clara Avenue field. Whittier Pipeline Corporation receives a portion of natural gas and natural gas liquid sales for processing and transporting.
97
Union Island Pipeline. We own the Union Island Pipeline, a 34-mile natural gas pipeline running from the Union Island field to a location near Pittsburg, California. The 12-inch line has an operating capacity of 52 MMcf/d and a maximum operating pressure rating of 1,000 psi. Currently, the pipeline is moving approximately 28 MMcf/d of natural gas at 650 psi to a connecting carrier that supplies a San Francisco Bay Area refinery. A little over half of the capacity is leased to a third party under a lease that terminates in November 2012, and may be extended annually until 2020 at the lessee's option. Volumes on the pipeline are shipped under contractual agreements.
Venoco Right of First Refusal and Maintenance Right. Venoco depends on a number of our pipeline assets to transport its oil and natural gas production. To enable Venoco to ensure the availability of those assets for the delivery of its production, the omnibus agreement provides that Venoco will have (i) a right of first refusal in the event we propose to sell or otherwise dispose of any of those assets and (ii) the right to require us to perform maintenance on, or promptly repair any defect in, any of those assets, in each case at our expense, if Venoco reasonably determines that the action is necessary or advisable to ensure the continued operation of the asset.
Oil and Natural Gas Data
Oil and Natural Gas Reserves
The following table sets forth our estimated proved reserves for the dates indicated. Our reserve estimates as of December 31, 2004, 2005 and 2006 are based on evaluations prepared by our internal reserve engineers, which were derived from the external reserve reports prepared by our independent reserve engineers. The reserve estimates were based upon our reserve engineers' review of production histories and other geological, economic, ownership and engineering data contained in reserve reports prepared by our independent reserve engineers.
| | Historical
| | Pro Forma
|
---|
| | December 31,
| | December 31,
|
---|
| |
| |
|
---|
| | 2004
| | 2005
| | 2006
| | 2006
|
---|
Estimated proved reserves: | | | | | | | | |
Oil (MBbl) | | | | | | | | |
| Developed | | 7,403 | | 7,204 | | 13,013 | | 14,886 |
| Undeveloped | | 1,035 | | 1,599 | | 1,136 | | 3,383 |
| |
| |
| |
| |
|
| | Total | | 8,438 | | 8,803 | | 14,149 | | 18,269 |
Natural gas (MMcf) | | | | | | | | |
| Developed | | 6,361 | | 12,610 | | 12,503 | | 13,731 |
| Undeveloped | | 1,508 | | 3,762 | | 2,599 | | 3,752 |
| |
| |
| |
| |
|
| | Total | | 7,869 | | 16,372 | | 15,102 | | 17,483 |
| |
| |
| |
| |
|
Total estimated proved reserves (MBoe) | | 9,749 | | 11,531 | | 16,666 | | 21,183 |
| |
| |
| |
| |
|
As of December 31, 2006, our estimated proved reserves totaled 16.7 MMBoe (90.6% proved developed), comprised of 14.1 MMBbl of oil (84.9% of the total) and 15.1 MMcf of natural gas, and had an estimated proved reserves to production ratio of 15 years. Please read "Glossary of Oil and Natural Gas Terms" for an explanation of the terms "proved reserves," "proved developed reserves," "proved undeveloped reserves" and related terms. You should not place undue reliance on estimates of proved reserves. Please read "Risk Factors—Risks Related to Our Business—Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantity and present value of our reserves."
98
Production, Prices and Costs
The following table sets forth certain information regarding our net production volumes, average sales prices realized and certain expenses associated with sales of oil and natural gas for the periods indicated. We urge you to read this information in conjunction with the information contained in our financial statements and related notes included elsewhere in this prospectus. The information set forth below is not necessarily indicative of future results.
| | Historical
|
---|
| | Years Ended December 31,
|
---|
| | 2004
| | 2005
| | 2006
|
---|
Production volume: | | | | | | | | | |
| Oil (MBbl) | | | 628 | | | 607 | | | 905 |
| Natural gas (MMcf) | | | 761 | | | 1,090 | | | 1,009 |
| MBoe | | | 755 | | | 789 | | | 1,073 |
Daily average production volume: | | | | | | | | | |
| Oil (Bbl/d) | | | 1,716 | | | 1,663 | | | 2,480 |
| Natural gas (Mcf/d) | | | 2,078 | | | 2,986 | | | 2,763 |
| Boe/d | | | 2,063 | | | 2,161 | | | 2,940 |
Realized price (in dollars)(1): | | | | | | | | | |
| Oil (per Bbl) | | $ | 36.12 | | $ | 49.57 | | $ | 57.77 |
| Natural gas (per Mcf) | | | 5.97 | | | 7.15 | | | 6.25 |
| Per Boe | | | 36.07 | | | 48.03 | | | 54.59 |
Expense per Boe: | | | | | | | | | |
| Lease operating expenses | | $ | 16.37 | | $ | 18.18 | | $ | 22.39 |
| Production and property taxes | | | 0.35 | | | 0.46 | | | 1.37 |
| Transportation expenses | | | 0.75 | | | 0.90 | | | 0.90 |
| Depreciation, depletion and amortization | | | 3.05 | | | 3.51 | | | 5.16 |
| General and administrative expense | | | 1.75 | | | 2.52 | | | 3.77 |
- (1)
- Amounts shown are based on oil and natural gas sales, net of inventory changes, realized commodity derivative gains (losses), and amortization of derivative premiums, divided by sales volumes.
Developed and Undeveloped Acreage
The Partnership Properties include proved undeveloped reserves, representing 18.1% of our estimated proved reserves. The following table summarizes our estimated developed and undeveloped leasehold acreage as of December 31, 2006. We have excluded acreage in which our interest is limited to a royalty or overriding royalty interest.
| | Developed
| | Undeveloped
| | Total
|
---|
Area
|
---|
| Gross
| | Net
| | Gross
| | Net
| | Gross
| | Net
|
---|
California | | | | | | | | | | | | |
| Coastal(1) | | 7,200 | | 2,244 | | 2,225 | | 1,347 | | 9,424 | | 3,590 |
| Other | | 4,853 | | 2,426 | | 638 | | 319 | | 5,491 | | 2,745 |
Texas | | 2,528 | | 2,196 | | — | | — | | 2,528 | | 2,196 |
| |
| |
| |
| |
| |
| |
|
Total | | 14,581 | | 6,866 | | 2,863 | | 1,666 | | 17,443 | | 8,531 |
| |
| |
| |
| |
| |
| |
|
- (1)
- Includes onshore and offshore properties in southern California.
99
Drilling Activity
No wells were drilled on the Partnership Properties in the years ended December 31, 2004 through December 31, 2006.
Operations
General
Pursuant to the administrative services agreement, Venoco will manage substantially all of our assets and will act as operator for our wells that are not operated by third parties. Venoco employs production and reserve engineers, geologists and other specialists, as well as field personnel that will perform land and engineering services for our properties under the administrative services agreement. As operator, Venoco designs and manages operation and maintenance activities on a day-to-day basis. Venoco operates interests that accounted for 80.8% of our pro forma production for the nine months ended September 30, 2007.
Marketing and Major Customers
Markets for oil and natural gas are volatile and are subject to wide fluctuations depending on numerous factors beyond our control, including seasonality, economic conditions, foreign imports, political conditions in other energy producing countries, OPEC market actions, and domestic government regulations and policies. All of our production is sold to competing buyers, including large oil refining companies and independent marketers. In the year ended December 31, 2006, approximately 90% of our revenues were generated from sales to four purchasers: ConocoPhillips (38%), Shell Trading (US) Co. (10%), Gulfmark Energy (28%), and Tesoro Refining and Marketing Company (14%). Substantially all of our production is sold pursuant to agreements with pricing based on prevailing commodity prices, subject to adjustment for regional differentials and similar factors.
Venoco will resell the majority of our natural gas production under individually negotiated natural gas purchase contracts using market sensitive pricing. Venoco's natural gas contracts vary in length from spot market sales of a single day to term agreements that may extend for one year or more.
Hedging Activity
We will enter into hedging transactions with unaffiliated third parties with respect to oil and natural gas prices in order to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in commodity prices. For a more detailed discussion of our hedging activities, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Overview" and "—Quantitative and Qualitative Disclosures About Market Risk."
Competition
The oil and natural gas business is highly competitive. We encounter strong competition in the search for and acquisition of additional reserves and in the sale of oil and natural gas. Our competitors principally consist of major and intermediate sized integrated oil and natural gas companies, independent oil and natural gas companies and individual producers and operators. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop our properties. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, these competitors may be able to pay more for properties and may be able to define, evaluate, bid for and purchase a greater number of properties than our financial or personal resources will permit. Ultimately, our future success will depend on our ability to develop or acquire additional reserves at costs that allow us to remain competitive.
100
Title to Properties
We believe that we have satisfactory title to all of our material assets. Title to our properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry. However, we believe that none of these liens, restrictions, easements, burdens and encumbrances materially detract from the value of our properties or from our interest in those properties or materially interfere with our use of those properties, in each case in the operation of our business as currently conducted. We believe that we have obtained sufficient right-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus. As is customary in the oil and natural gas industry, we typically make minimal investigation of title at the time we acquire undeveloped properties. We make title investigations and receive title opinions of local counsel only before we commence drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense.
Safety and Maintenance
The pipelines we use to gather and transport our oil and natural gas are subject to regulation by the federal Pipeline and Hazardous Materials Safety Administration ("PHMSA"), of the federal Department of Transportation ("DOT"), pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended ("NGPSA"), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979, as amended ("HLPSA"), with respect to oil. By adopting rules for intrastate pipelines at least as stringent as found at the federal level, California has been certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines and, consequently, has authorized the California Office of the State Fire Marshall to regulate the safety of our intrastate oil transportation pipelines. The NGPSA and the HLPSA regulate safety requirements in the design, construction, operation and maintenance of natural gas and oil pipeline facilities. Both the NGPSA and the HLPSA have been amended in recent years by the Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. These amended pipeline safety rules have resulted in the adoption of rules by the DOT that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in "high consequence areas," such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. Between 2005 and 2007, Venoco has performed and completed baseline investigations of the integrity of our transportation pipelines in those areas where a leak or rupture could potentially affect high consequence areas. The next phase of integrity investigations on these pipelines is not expected to commence until 2009, at the earliest. Currently, we believe our pipelines are in substantial compliance with NGPSA, HLPSA and the more recent 2002 and 2006 amendments to those acts. Nonetheless, significant expenses could be incurred if new or more stringently interpreted pipeline safety requirements are implemented.
The safety of our producing and non-producing operations also is regulated by the federal Minerals Management Service, the U.S. Coast Guard, the Occupational Health and Safety Administration and the California State Lands Commission. The federal Occupational Safety and Health Act ("OSHA") and comparable state laws protect the health and safety of workers, both generally and within the pipeline and oil and gas industry. In addition, the OSHA hazardous communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such
101
information be provided to employees, state and local government authorities and citizens. Our operations are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns, and wells in excess of 10,000 pounds at various locations. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements and, as part of that program, are currently assessing the recently acquired West Montalvo field to assure conformity with these safety requirements. We believe that we are in substantial compliance with applicable laws and regulations relating to worker health and safety. In the event that new or more stringently interpreted measures are required in the future, we could incur significant expenses to meet those requirements.
Regulatory Environment
Our oil and natural gas exploration, production and transportation activities are subject to extensive regulation at the federal, state and local levels. These regulations relate to, among other things, environmental and land-use matters, conservation, safety, pipeline use, drilling and spacing of wells, well stimulation, transportation, and forced pooling and protection of correlative rights among interest owners. The following is a summary of some key regulations that affect our operations.
Environmental and Land Use Regulation
A wide variety of environmental and land use regulations apply to companies engaged in the production and sale of oil and natural gas. These regulations have been changed frequently in the past and, in general, these changes have imposed more stringent requirements that increase operating costs and/or require capital expenditures to remain in compliance. We believe that our business operations are in substantial compliance with current laws and regulations. Failure to comply with these requirements can result in administrative, civil and/or criminal penalties and liability for non-compliance, clean-up costs and other environmental damages. It also is possible that unanticipated developments or changes in the law could require us to make environmental expenditures significantly greater than those we currently expect.
California Environmental Quality Act ("CEQA"). CEQA is California legislation that requires consideration of the environmental impacts of proposed actions that may have a significant effect on the environment. CEQA requires the responsible governmental agency to prepare an environmental impact report that is made available for public comment. The responsible agency also is required to consider mitigation measures. The party requesting agency action bears the expense of the report.
We may be required to undergo the CEQA process for lease renewals and other proposed actions by state and local governmental authorities that meet specified criteria. At a minimum, the CEQA process delays and adds expense to the process of obtaining new or renewed leases and permits.
Discharges to Waters. The Federal Water Pollution Control Act of 1972, as amended ("Clean Water Act"), and comparable state statutes impose restrictions and controls on the discharge of produced waters and other oil and natural gas wastes into regulated waters, including wetlands. These controls generally have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. These laws prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and other substances related to the oil and natural gas industry into onshore, coastal and offshore waters without appropriate permits. Violation of the Clean Water Act and similar state regulatory programs can result in civil, criminal and administrative penalties for unauthorized discharges of oil, hazardous substances and other pollutants. They also can impose substantial liability for the costs of removal or remediation associated with discharges of oil or hazardous substances.
102
The Clean Water Act also regulates stormwater discharges from industrial properties and construction activities, and requires separate permits and implementation of a Stormwater Pollution Prevention Plan ("SWPPP") establishing best management practices, training, and periodic monitoring of covered activities. Certain operations also are required to develop and implement Spill Prevention, Control, and Countermeasure ("SPCC") plans or facility response plans to address potential oil spills.
Oil Spill Regulation. The Oil Pollution Act of 1990, as amended ("OPA"), amends and augments the Clean Water Act as it relates to oil spills. It imposes liability on responsible parties without regard to fault for the costs of cleanup and other damages resulting from an oil spill in waters of the United States. Responsible parties include (i) owners and operators of onshore facilities and pipelines and (ii) lessees or permittees of offshore facilities. In addition, OPA requires parties responsible for offshore facilities to provide financial assurance in the amount of $35.0 million, which can be increased to $150.0 million in some circumstances, to cover potential OPA liabilities.
Regulations imposed by the federal Minerals Management Service ("MMS") also require oil-spill response plans and oil-spill financial assurance from offshore oil and natural gas operations, whether operating in state or federal offshore waters. These regulations were designed to be consistent with OPA and other similar requirements. Under MMS regulations, operators must join a cooperative that makes oil-spill response equipment available to its members. The California Department of Fish and Game's Office of Oil Spill Prevention and Response ("OSPR") has adopted oil-spill prevention regulations that overlap with federal regulations.
Air Emissions. Our operations are subject to local, state and federal regulations governing emissions of air pollutants. Local air-quality districts are responsible for much of the regulation of air-pollutant sources in California. California requires new and modified stationary sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally-based permitting requirements. Because of the severity of ozone levels in portions of California, the state has severe restrictions on emissions of volatile organic compounds ("VOCs") and nitrogen oxides ("NOX"). Producing wells, natural gas plants and electric generating facilities all generate VOCs and NOX. Some of our producing wells are in counties that are designated as non-attainment for ozone and, therefore, potentially are subject to restrictive emission limitations and permitting requirements. California also operates a stringent program to control hazardous (toxic) air pollutants, and this program could require the installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits generally are resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could require us to forego construction, modification or operation of certain air-emission sources. Air emissions from oil and natural gas operations also are regulated by oil and natural gas permitting agencies, including the MMS, the State Lands Commission and other local agencies.
Waste Disposal. We currently own or lease a number of properties that have been used for production, gathering or transportation of oil and natural gas for many years. Although we believe the prior owners and/or operators of those properties generally utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties we currently own, lease or have a right of easement. State and federal laws applicable to oil and natural gas wastes have become more stringent. Under applicable laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed of or released by prior owners or operators) or to perform remedial well-plugging operations to prevent future, or mitigate existing, contamination.
We may generate wastes, including "solid" wastes and "hazardous" wastes, that are subject to the federal Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable state statutes, although certain oil and natural gas exploration and production wastes currently are exempt
103
from regulation as hazardous wastes under RCRA. Moreover, the U.S. Environmental Protection Agency ("EPA") has limited the disposal options for certain wastes that are designated as hazardous wastes under RCRA. Nonetheless, it is possible that certain wastes generated by our oil and natural gas operations that currently are exempt from regulation as hazardous wastes may in the future be designated as hazardous wastes, and therefore be subject to more rigorous and costly management, disposal and clean-up requirements. State and federal oil and natural gas regulations also provide guidelines for the storage and disposal of solid wastes resulting from the production of oil and natural gas, both onshore and offshore.
Superfund. Under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended, also known as CERCLA or the Superfund law, and similar state laws, responsibility for the entire cost of cleanup of a contaminated site, as well as natural resource damages, can be imposed upon current or former site owners or operators, or upon any party who released one or more designated "hazardous substances" at the site, regardless of the lawfulness of the original activities that led to the contamination. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the potentially responsible parties the costs of such action. Although CERCLA generally exempts petroleum from the definition of hazardous substances, in the course of our operations we generate wastes that fall within CERCLA's definition of hazardous substances. We may also be an owner or operator of facilities at which hazardous substances have been released by previous owners or operators. We may be responsible under CERCLA for all or part of the costs of cleaning up facilities at which hazardous substances have been released and for natural resource damages. To our knowledge, we have not been identified as a potentially responsible party under CERCLA, nor are we aware of any prior owners or operators of our properties that have been so identified with respect to their ownership or operation of those properties.
Abandonment, Decommissioning and Remediation Requirements. Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production and transportation facilities and the environmental restoration of operations sites. MMS regulations, coupled with applicable lease and permit requirements and each property's specific development and production plan, prescribe the requirements for decommissioning our federally leased offshore facilities. The California State Lands Commission ("CSLC"), and the California Department of Conservation, Division of Oil, Gas and Geothermal Resources ("DOGGR") are the principal state agencies responsible for regulating the drilling, operation, maintenance and abandonment of all oil and natural gas wells in the state, whether onshore or offshore. MMS regulations require federal leaseholders to post performance bonds. Please read "—Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations—Plugging and Abandonment Costs" for a discussion of our principal obligations relating to the abandonment and decommissioning of our facilities.
California Coastal Act. The California Coastal Act regulates the conservation and development of California's coastal resources. The California Coastal Commission (the "Coastal Commission") works with local governments to make permit decisions for new developments in certain coastal areas and reviews local coastal programs, such as land-use restrictions. The Coastal Commission also works with the OSPR to protect against and respond to coastal oil spills. The Coastal Commission has direct regulatory authority over offshore oil and natural gas development within the state's three mile jurisdiction and has authority, through the Federal Coastal Zone Management Act, over federally permitted projects that affect the state's coastal zone resources. We conduct activities that may be subject to the California Coastal Act and the jurisdiction of the Coastal Commission.
Other Environmental Laws and Regulation. Our leases in federal waters on the Outer Continental Shelf are administered by the MMS and require compliance with detailed MMS regulations and orders.
104
Under certain circumstances, the MMS may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition and operations.
Our offshore leases in state waters or "tidelands" (within three miles of the coastline) are administered by the state of California and require compliance with certain regulations of the CLSC and DOGGR. The CSLC serves as the lessor of our state offshore leases and is charged with overseeing leasing, exploration, development and environmental protection of the state tidelands.
Commencing with the Cunningham Shell Act of 1955, California has enacted several pieces of legislation that withhold state tidelands from oil and natural gas leasing. The Cunningham Shell Act protected an area of tidelands offshore Santa Barbara County that stretches west from Summerland Bay to Coal Oil Point, and included waters offshore the unincorporated area of Montecito, the City of Santa Barbara and the University of California at Santa Barbara. It also protected the state tidelands around the islands of Anacapa, Santa Cruz, Santa Rosa and San Miguel. In 1994, California enacted the California Sanctuary Act which, with three exceptions, prohibits leasing of any state tidelands for oil and natural gas development. Oil and natural gas leases in effect as of January 1, 1995 are unaffected by this legislation until such leases revert back to the state, at which time they will become part of the California Coastal Sanctuary. This legislation does not restrict our existing state offshore leases or our current or planned future operations.
Recent and future environmental regulations, including additional federal and state restrictions on greenhouse gas ("GHG") emissions that may be passed in response to climate change concerns, may increase our operating costs and also reduce the demand for the oil and natural gas we produce. The U.S. Congress is actively considering legislation to reduce emissions of greenhouse gases. One bill recently approved by the U.S. Senate Environment and Public Works Committee, known as the Lieberman-Warner Climate Security Act or S.2191, would require a 70% reduction in emissions of GHGs from sources within the United States between 2012 and 2050. The Lieberman-Warner bill proposes a "cap and trade" scheme of regulation of GHG emissions—a ban on emissions above a defined reducing annual cap. Covered parties will be authorized to emit GHG emissions through the acquisition and subsequent surrender of emission allowances that may be traded or acquired on the open market. If this bill is passed, we could be required to purchase and surrender allowances either for GHG emissions resulting from our operations or from combustion of fuels we produce. A vote on this bill by the full Senate is expected to occur before mid-year 2008. Notwithstanding action at the federal level, on September 27, 2006, California's governor signed into law the "California Global Warming Solutions Act of 2006" Assembly Bill (AB) 32, which establishes a statewide cap on GHGs that will reduce the state's GHG emissions to 1990 levels by 2020. The California Air Resources Board ("CARB") has been designated as the lead agency to establish and adopt regulations to implement AB 32 by January 1, 2012. Similar regulations may be adopted by other states in which we operate or by the federal government. Also, as a result of the U.S. Supreme Court's decision on April 2, 2007 inMassachusetts, et al. v. EPA, the EPA may be required to regulate GHG emissions from mobile sources (e.g., cars and trucks) even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The EPA has indicated that it will issue a rulemaking notice to address carbon dioxide and other GHG emissions from vehicles and automobile fuels, although the date for issuance of this notice has not been finalized. The Court's holding inMassachusetts that GHG emissions fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of GHG emissions from stationary sources under certain Clean Air Act programs. Although we would not be impacted to a greater degree than other similarly situated producers of oil and gas, a stringent GHG control program could have an adverse effect on our cost of doing business and could reduce demand for the oil and gas we produce.
In addition, the federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security ("DHS") to issue regulations establishing risk-based performance
105
standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and, on November 20, 2007, further issued a final rule that revised the list of chemicals of interest and their respective threshold quantities that will trigger compliance with the interim final rule. We have not yet determined the extent to which our facilities are subject to the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.
Other environmental protection statutes that may impact our operations included the Marine Mammal Protection Act, the Marine Life Protection Act, the Marine Protection, Research, and Sanctuaries Act of 1972, the Endangered Species Act, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act.
Potentially Material Costs Associated with Environmental Regulation of Our Oil and Natural Gas Operations
Significant potential costs relating to environmental and land-use regulations associated with our existing properties and operations include those relating to (i) plugging and abandonment of facilities, (ii) clean-up costs and natural resource damages due to spills or other releases and (iii) penalties imposed for spills, releases or non-compliance with applicable laws and regulations. As is customary in the oil and natural gas industry, we typically have contractually assumed, and may assume in the future, obligations relating to plugging and abandonment, clean-up and other environmental costs in connection with our acquisition of operating interests in fields, and these costs can be significant.
Plugging and Abandonment Costs. Our operations, and in particular our offshore platforms and related facilities, are subject to stringent abandonment and closure requirements imposed by the MMS and the state of California. In connection with its acquisition of a 25% interest in the Dos Cuadras field in 1999 from Chevron, Venoco assumed all abandonment obligations associated with its 25% interest in the infrastructure (but not the wells) in the Dos Cuadras field. We will assume these obligations at the closing of this offering, subject to Venoco's obligation to indemnify us in certain circumstances. Venoco also assumed all of the abandonment costs relating to the operations, including platform Holly, in the South Ellwood field when it purchased the field from Mobil Oil Corporation in 1997. At the closing of this offering, we will enter into an agreement with Venoco pursuant to which we will be responsible for 23% of the principal abandonment costs associated with the South Ellwood field, including onshore facilities. Please read "Certain Relationships and Related Party Transactions—Agreements Relating to Our Operations."
As described in note 4 to our financial statements, we have estimated the present value of our aggregate asset retirement obligations to be $11.4 million as of December 31, 2006. This figure reflects the expected future costs associated with site reclamation, facilities dismantlement and plugging and abandonment of wells. The discount rates used to calculate the present value varied depending on the estimated timing of the obligation, but typically ranged between 5% and 9%. Actual costs may exceed our estimates. Our financial statements do not reflect any reserves relating to other environmental obligations that may arise or be identified in the future.
Under a variety of applicable laws and regulations, including CERCLA, RCRA and MMS regulations, we could in some circumstances be held responsible for abandonment and clean-up costs relating to our operations, both onshore and offshore, notwithstanding contractual arrangements that assign responsibility for those costs to other parties.
Clean-up Costs. Venoco's onshore facility at the South Ellwood field is known to have hydrocarbon contamination. Because oil occurs naturally in the area, regulators have not yet determined the applicable cleanup requirements for this facility. We expect that Venoco will be permitted to defer remedial actions at the facility until operations there cease, and Venoco's present
106
intention is to continue using it for the foreseeable future. We currently estimate that the cost of a clean-up of the facility will be between $2.0 and $5.0 million. As noted above, we will be responsible for 23% of the abandonment costs associated with the facility. The estimated costs relating to this obligation are included in the asset retirement obligations shown in our financial statements. For the purpose of calculating the asset retirement obligation, we estimated that the facility has a remaining useful life of 20 years.
Penalties for Non-Compliance. We believe that our operations are in material compliance with all applicable oil and natural gas, safety, environmental and land-use laws and regulations. However, from time to time we receive notices of noncompliance with Clean Air Act and other requirements from relevant regulatory agencies. There are no notices of noncompliance that we believe are materially adverse to our operations.
Transportation Regulation
General Interstate Regulation. Our interstate common carrier pipeline operations are subject to rate regulation by FERC under the ICA. The ICA requires that tariff rates for petroleum pipelines, which include both oil pipelines and refined products pipelines, be just and reasonable and non-discriminatory.
State Regulation. Our intrastate oil pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies, including the CPUC. The CPUC regulates the rates, terms, and conditions applicable to intrastate transportation of oil by pipeline in California. Pursuant to Section 854 of the California Public Utilities Code, we must obtain approval from the CPUC prior to any transfer of our CPUC-regulated oil pipelines. Accordingly, our ownership of this CPUC-regulated oil pipelines is contingent upon receiving this approval from the CPUC.
Energy Policy Act of 1992 and Subsequent Developments. FERC's oil pipeline indexing methodology allows a pipeline to increase its rates annually by a percentage equal to the change in the producer price index for finished goods ("PPI-FG") plus 1.3% to the new ceiling level. Rate increases made pursuant to the indexing methodology are subject to protest, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline's increase in costs. If the PPI-FG falls and the indexing methodology results in a reduced ceiling level that is lower than a pipeline's filed rate, Order No. 561 requires the pipeline to reduce its rate to comply with the lower ceiling unless doing so would reduce a rate "grandfathered" by the Energy Policy Act of 1992, or EPAct 1992, below the grandfathered level. A pipeline must, as a general rule, utilize the indexing methodology to change its rates, although FERC retains cost-of-service ratemaking and other ratemaking approaches. FERC's indexing methodology is subject to review every five years; the current methodology is expected to remain in place through June 30, 2011. If FERC continues its policy of using the PPI-FG plus 1.3%, changes in that index might not fully reflect actual increases in the costs associated with the pipelines subject to indexing, thus hampering our ability to recover cost increases.
EPAct 1992 deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPAct 1992 that had not been subject to complaint, protest or investigation during that 365-day period to be just and reasonable under the ICA. Generally, complaints against such "grandfathered" rates may only be pursued if the complainant can show that a substantial change has occurred since the enactment of EPAct 1992 in either the economic circumstances of the oil pipeline, or in the nature of the services provided, that were a basis for the rate. EPAct 1992 places no such limit on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential. Two of the three FERC rates that are in effect for our interstate oil pipelines are grandfathered under EPAct 1992.
107
In May 2007, the D.C. Circuit approved FERC's policy permitting the inclusion of an income tax allowance in the cost-of-service based rates of a pipeline organized as a tax pass-through partnership entity if the pipeline proves that the ultimate owner of its equity interests has an actual or potential income tax liability on public utility income. The policy also provides that whether a pipeline's owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. Although the FERC's current income tax allowance policy is generally favorable for pipelines that are organized as pass-through entities, such as publicly traded partnerships, it still entails rate risk due to the case-by-case review requirement. Under FERC's current income tax allowance policy, if our interstate oil pipeline rates were subject to review in a proceeding before FERC, we could be required to demonstrate that the equity interest owners incur actual or potential income tax liability on their respective shares of partnership public utility income. While we have established the Eligible Holder certification requirement, we can provide no assurance that such certification will be effective to establish that our unitholders, or our unitholders' owners, are subject to income taxation on the public utility income generated by us or the applicable tax rate that should apply to such unitholders. If we are unable to do so, FERC could decide to reduce our rates from current levels. We can give no assurance that in the future FERC's current income tax allowance policy or its application will not be changed.
Proposed Proxy Policy Statement. FERC also has pending a proceeding regarding the methodology to be used for determining natural gas and oil pipeline equity returns to be included in cost-of-service based rates and regarding the appropriate composition of proxy groups to be used in the methodology.
The ultimate outcome of this proceeding is not certain and may result in new policies being established at FERC that would not allow the full use of distributions to unitholders by pipeline publicly traded partnerships in any proxy group comparisons used to determine return on equity in future rate proceedings. We cannot ensure that such policy developments would not adversely affect our FERC-regulated pipelines' ability to achieve a reasonable level of return on equity in any future rate proceeding.
Energy Policy Act of 2005. The Energy Policy Act of 2005, or EPAct 2005, amends the Natural Gas Act, or NGA, to add an anti-manipulation provision which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations prescribed by FERC and provides FERC with civil penalty authority under the NGA. The FERC issued a rule implementing the anti-manipulation provision of EPAct 2005, which makes it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted "in connection with" natural gas sales, purchases or transportation subject to FERC jurisdiction. EPAct 2005 also amends the NGA and the Natural Gas Policy Act to give FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation for violations occurring after August 8, 2005. The anti-manipulation rule and enhanced civil penalty authority reflect an expansion of FERC's enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts.
Regulation of OCS Pipelines. The OCSLA requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. The MMS has a pending rulemaking proceeding that would establish a process for a shipper transporting oil or natural gas
108
production from OCS leases to follow if it believes it has been denied open and nondiscriminatory access to OCS pipelines. The MMS proposal includes a provision for civil penalties of up to $10,000 per day for violations of the open and nondiscriminatory access requires of the OCSLA. We have no way of knowing what rules the MMS will ultimately adopt regarding access to OCS transportation and what effect, if any, those rules will have on our OCS pipeline operations, revenues, and profitability.
Employees
Neither we, our subsidiaries, or our general partner have employees, but at the closing of this offering, we will enter into an administrative services agreement with Venoco pursuant to which Venoco will perform administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering. As of September 30, 2007, Venoco had approximately 277 full time employees. None of these employees are covered by collective bargaining agreements. Venoco considers its relationships with its employees to be strong.
Legal Proceedings
As of the date of this registration statement, we are not a party to any material pending legal proceedings. Certain of the properties that we will acquire upon completion of this offering are subject to ongoing litigation. Please read "Certain Relationships and Related Party Transactions—Agreements Relating to Our Operations—Omnibus Agreement." In addition, from time to time, we may be subject to claims and litigation in the ordinary course of our business. We maintain liability insurance and believe that our coverage is reasonable in view of the legal risks to which our business ordinarily is subject.
109
MANAGEMENT
Management of Our Partnership
Our general partner will manage our operations and activities, and its board of directors and officers will make decisions on our behalf. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly nonrecourse to it. Our general partner may cause us to incur indebtedness or other obligations that are nonrecourse to it.
Our general partner is a wholly owned indirect subsidiary of Venoco and will oversee our operations. Of the directors elected by Venoco, three directors will be independent as defined under the independence standards established by the NYSE. The NYSE does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a nominating and governance committee.
In compliance with the requirements of the NYSE, Venoco expects to appoint Charles Leonard and Timothy Brittan as independent members to the board of directors of our general partner at the closing of this offering and a third independent member within 12 months of the effective date of the registration statement. The independent members of the board of directors of our general partner will serve as the initial members of the conflicts and audit committees of the board of directors of our general partner.
Pursuant to the terms of our limited partnership agreement and the limited liability company agreement of our general partner, our general partner will not be permitted to cause us, without the prior approval of Venoco, to:
- •
- sell all or substantially all of our assets;
- •
- merge or consolidate;
- •
- dissolve or liquidate;
- •
- make or consent to a general assignment for the benefit of creditors;
- •
- file or consent to the filing of any bankruptcy, insolvency or reorganization petition for relief under the United States Bankruptcy Code or otherwise seek protection from creditors; or
- •
- take various actions similar to the foregoing.
At least two members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Securities Exchange Act of 1934, as amended, to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners, and not a breach by our general partner of any duties it may owe us or our unitholders.
In addition, our general partner will have an audit committee ultimately composed of at least three directors who meet the independence and experience standards established by the NYSE and the Securities Exchange Act of 1934, as amended. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory
110
requirements and corporate policies and controls. The audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee. Venoco Acquisition Company GP, LLC will also have a compensation committee, which will among other things, oversee the compensation plans described below.
The officers of our general partner will manage the day-to-day affairs of our business. We will also utilize a significant number of employees of Venoco to operate our properties and provide us with certain general and administrative services. We will reimburse Venoco for allocated expenses of operational personnel who perform services for our benefit. The reimbursement of the costs attributable to the operating and administrative services provided to us by Venoco will be structured in the form of a fee that is billed on a monthly basis. Please read "—Reimbursement of Expenses of Our General Partner."
Directors and Executive Officers
The following table shows information regarding the current director, director nominees and executive officers of our general partner. Directors are elected for one-year terms.
Name
| | Age
| | Position with Venoco Acquisition Company GP, LLC
|
---|
Timothy Marquez | | 49 | | Chairman and Chief Executive Officer |
William Schneider | | 46 | | President |
Mark DePuy | | 52 | | Senior Vice President, Chief Operating Officer |
Timothy Ficker | | 40 | | Chief Financial Officer |
Terry L. Anderson | | 60 | | General Counsel and Secretary |
Charles H. Leonard | | 59 | | Director nominee |
J. Timothy Brittan | | 53 | | Director nominee |
Our directors hold office until the earlier of their death, resignation or removal or until their successors have been elected. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.
Timothy Marquez was elected Chairman and Chief Executive Officer of our general partner in October 2007. Mr. Marquez co-founded Venoco in September 1992 and served as its CEO from its formation until June 2002. He founded Marquez Energy in 2002 and served as its CEO until Venoco acquired it in March 2005. Mr. Marquez returned as Venoco's Chairman, CEO and President in June 2004. Mr. Marquez has a B.S. in petroleum engineering from the Colorado School of Mines. Mr. Marquez began his career with Unocal Corporation, where he worked for 13 years managing assets offshore California and in the North Sea and performing other managerial and engineering functions.
William Schneider was elected President of our general partner in October 2007. Mr. Schneider became Venoco's President in January 2005. Prior to joining Venoco, Mr. Schneider was a managing director at BMO Capital Markets (formerly known as Harris Nesbitt), an investment bank, where he focused on mergers and acquisitions in the energy industry. He joined BMO Capital Markets in February 2001. From January 1998 to January 2001, he worked in the Energy Investment Banking division of Donaldson, Lufkin & Jenrette. Mr. Schneider's experience also includes service in Smith Barney's Energy Investment Banking division. Before entering investment banking, Mr. Schneider held a variety of engineering and corporate positions at Unocal for over 12 years. Mr. Schneider holds an M.B.A. in Finance from U.C.L.A. and a B.S. in petroleum engineering from the Colorado School of Mines.
111
Mark DePuy was elected Senior Vice President and Chief Operating Officer of our general partner in October 2007. Mr. DePuy became Venoco's Vice President, Northern Assets, in August 2005 and was promoted to Senior Vice President and Chief Operating Officer in January 2006. Prior to joining Venoco, he spent 27 years with Unocal in a variety of domestic and international operating and business planning roles, most recently as a corporate planning manager for worldwide operations. With Unocal, Mr. DePuy spent 13 years working on operations onshore and offshore coastal California. He has an M.B.A. from U.C.L.A. and a B.S. in petroleum engineering from the Colorado School of Mines.
Timothy Ficker was elected Chief Financial Officer of our general partner in October 2007. Mr. Ficker joined Venoco as CFO in April 2007. Prior to that Mr. Ficker was Vice President, CFO and Secretary of Infinity Energy Resources, Inc., a NASDAQ-listed energy company, having been appointed to those positions in May 2005. From October 2003 through April 2005, Mr. Ficker served as an audit partner in KPMG LLP's Denver office, and from June 2002 through September 2003, he served as an audit director for KPMG LLP. From September 1989 through June 2002, he worked for Arthur Andersen LLP, including as an audit partner after September 2001, where he served clients primarily in the energy industry. Mr. Ficker is a certified public accountant and received a B.B.A. in accounting from Texas A&M University.
Terry L. Anderson was elected General Counsel and Secretary of our general partner in October 2007. Mr. Anderson joined Venoco in March 1998 and served as its General Counsel until June 2002. From July 2002 to August 2004, Mr. Anderson was in private practice in Santa Barbara, California. He returned as Venoco's General Counsel and Secretary in August 2004. Mr. Anderson holds a B.S. in petroleum engineering and a J.D. from the University of Southern California. Mr. Anderson was Vice President and General Counsel of Monterey Resources, Inc., a NYSE-listed company, from August 1996 to January 1998. Prior to that, he was chief transactional attorney for Santa Fe Energy Resources in Houston, Texas. Mr. Anderson is licensed to practice law in Texas and California.
Charles H. Leonard is expected to be elected to our general partner's board of directors prior to or at the closing of this offering. Mr. Leonard has served as a member of the board of directors and audit committee of Delek US Holdings, Inc., a diversified energy business focused on petroleum refining, wholesale sales of refined products and retail marketing, since May 2006. From March 2006 to March 2007, Mr. Leonard served as the chief financial officer of EGL, Inc., a publicly traded company that provides transportation, supply chain management and information services. From September 2005 to December 2005, Mr. Leonard was the chief financial officer of, and from January 2006 to February 2006 was a consultant to, Transport Industries Holdings, Inc., a privately held transportation and logistics company. From September 1988 to July 2005, Mr. Leonard was employed by Texas Eastern Products Pipeline Company, LLC, the general partner of TEPPCO Partners, L.P., a publicly traded master limited partnership, that owns and operates common carrier pipelines for the transportation of refined petroleum products, liquified petroleum and natural gases, crude oil and petrochemicals. Mr. Leonard was responsible for the financial operations of the company and served in various capacities, including treasurer from 1996 to 2002 and senior vice president commencing in 1990 and chief financial officer commencing in 1989.
J. Timothy Brittan is expected to be elected to our general partner's board of directors prior to or at the closing of this offering. Mr. Brittan has served as a director of Venoco since May 2003 and has 25 years experience in the oil and natural gas industry. He has served as the President of Infinity Oil & Gas, Inc., an exploration and production company, since July 1989. Mr. Brittan attended the Colorado School of Mines.
Reimbursement of Expenses of Our General Partner
Our general partner will not receive any management fee or other compensation for its management of our partnership. Under the terms of the omnibus agreement, we will reimburse Venoco
112
for the payment of general and administrative services incurred for our benefit. The omnibus agreement will further provide that we will reimburse Venoco for our allocable portion of the premiums on insurance policies covering our assets. For a description of the terms of the omnibus agreement, please read "Certain Relationships and Related Party Transactions—Agreements Relating to Our Operations—Omnibus Agreement."
Executive Compensation
Venoco Acquisition Company GP, LLC, our general partner, was formed in 2007. Accordingly, our general partner has not accrued any obligations with respect to compensation for its directors and officers for the 2006 fiscal year. Our general partner will not have any employees. The compensation of the executive officers of our general partner will be set by the compensation committee of our general partner's board of directors. The officers and employees of Venoco Acquisition Company GP, LLC may participate in employee benefit plans and arrangements sponsored by Venoco. Venoco Acquisition Company GP, LLC has not entered into any employment agreements with any of its officers. We anticipate that its board of directors will grant awards to key employees and outside directors pursuant to the long-term incentive plan described below following the closing of this offering; however, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.
Compensation Discussion and Analysis
We do not directly employ any of the persons responsible for managing or operating our business. Instead, we are managed by our general partner, Venoco Acquisition Company GP, LLC, the executive officers of which are employees of Venoco. Prior to the completion of this offering, Venoco Acquisition Company GP, LLC will enter into the omnibus agreement with Venoco, pursuant to which, among other matters:
- •
- Venoco will make available to Venoco Acquisition Company GP, LLC the services of the Venoco employees who serve as the executive officers of Venoco Acquisition Company GP, LLC; and
- •
- Venoco Acquisition Company GP, LLC will be obligated to reimburse Venoco for any allocated portion of the costs that Venoco incurs in providing compensation and benefits to such Venoco employees.
Please read "Certain Relationships and Related Party Transactions" for a description of the omnibus agreement.
Although we will bear an allocated portion of Venoco's costs of providing compensation and benefits to the Venoco employees who serve as the executive officers of our general partner, we will have no control over such costs and will not establish or direct the compensation policies or practices of Venoco. We expect that each of these executive officers will continue to perform services for our general partner, as well as Venoco and its affiliates, after the completion of this offering.
Pursuant to the omnibus agreement between Venoco and our general partner, and the applicable provisions of our partnership agreement, we will bear an allocated portion of Venoco's costs of providing compensation and benefits to the Venoco employees who serve as the executive officers of our general partner.
We currently expect that, following the completion of this offering, we will bear substantially less than a majority of Venoco's costs of providing compensation and benefits to the Chief Executive Officer of our general partner (the principal executive officer) and the Chief Financial Officer of our general partner (the principal financial officer) during 2008. The principal executive officer and the principal financial officer, together, are our "named executive officers."
113
While we intend to adopt a long-term incentive plan, we currently do not intend to grant awards to our executive officers. Our board may grant awards to our executive officers in the future.
Compensation of Directors
Officers or employees of our general partner or its affiliates who also serve as directors will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that directors who are not its officers or employees or its affiliates will receive compensation for attending meetings of the board of directors and committee meetings. The amount of such compensation has not yet been determined. In addition, each non-employee director will be reimbursed for his out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us for his actions associated with being a director to the fullest extent permitted under Delaware law.
Long-Term Incentive Plan
General. Our general partner intends to adopt a long-term incentive plan, or the plan, for employees, consultants and directors of our general partner and its affiliates who perform services for us. The plan will provide for the grant of restricted units, phantom units, unit options and substitute awards and, with respect to unit options and phantom units, the grant of distribution equivalent rights, or DERs. Subject to adjustment for certain events, an aggregate of common units may be delivered pursuant to awards under the plan. Units that are canceled, forfeited or are withheld to satisfy our general partner's tax withholding obligations are available for delivery pursuant to other awards. The plan will be administered by the compensation committee of our general partner's board of directors.
Restricted Units and Phantom Units. A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the grantee receives a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of the compensation committee, cash equal to the fair market value of a common unit. The compensation committee may make grants of restricted units and phantom units under the plan to eligible individuals containing such terms, consistent with the plan, as the compensation committee may determine, including the period over which restricted units and phantom units granted will vest. The compensation committee may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria. In addition, the restricted and phantom units will vest automatically upon a change of control (as defined in the plan) of us or our general partner, subject to any contrary provisions in the award agreement.
If a grantee's employment, consulting or membership on the board terminates for any reason, the grantee's restricted units and phantom units will be automatically forfeited unless, and to the extent, the award agreement or the compensation committee provides otherwise. Common units to be delivered with respect to these awards may be common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring common units. If we issue new common units with respect to these awards, the total number of common units outstanding will increase.
Distributions made by us with respect to awards of restricted units may, in the compensation committee's discretion, be subject to the same vesting requirements as the restricted units. The compensation committee, in its discretion, may also grant tandem DERs with respect to phantom units
114
on such terms as it deems appropriate. DERs are rights that entitle the grantee to receive, with respect to a phantom unit, cash equal to the cash distributions made by us on a common unit.
We intend for the restricted units and phantom units granted under the plan to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.
Unit Options. The plan also permits the grant of options covering common units. Unit options may be granted to such eligible individuals and with such terms as the compensation committee may determine, consistent with the plan; however, a unit option must have an exercise price equal to the fair market value of a common unit on the date of grant.
Upon exercise of a unit option, our general partner will acquire common units in the open market at a price equal to the prevailing price on the principal national securities exchange upon which the common units are then traded, or directly from us or any other person, or use common units already owned by the general partner, or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the difference between the cost incurred by our general partner in acquiring the common units and the proceeds received by our general partner from an optionee at the time of exercise. Thus, we will bear the cost of the unit options. If we issue new common units upon exercise of the unit options, the total number of common units outstanding will increase, and our general partner will remit the proceeds it received from the optionee upon exercise of the unit option to us. The unit option plan has been designed to furnish additional compensation to employees, consultants and directors and to align their economic interests with those of common unitholders.
Substitution Awards. The compensation committee, in its discretion, may grant substitute or replacement awards to eligible individuals who, in connection with an acquisition made by us, our general partner or an affiliate, have forfeited an equity-based award in their former employer. A substitute award that is an option may have an exercise price less than the value of a common unit on the date of grant of the award.
Termination of Long-Term Incentive Plan. Our board of directors, in its discretion, may terminate the plan at any time with respect to the common units for which a grant has not theretofore been made. The plan will automatically terminate on the earlier of the 10th anniversary of the date it was initially approved by our unitholders or when common units are no longer available for delivery pursuant to awards under the plan. Our board of directors will also have the right to alter or amend the plan or any part of it from time to time and the committee may amend any award; provided, however, that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant. Subject to unitholder approval, if required by the rules of the principal national securities exchange upon which the common units are traded, our board of directors may increase the number of common units that may be delivered with respect to awards under the plan.
115
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth the beneficial ownership of our units that will be issued at the closing of this offering and the related transactions and held by:
- •
- each person who then will beneficially own 5% or more of the then outstanding units;
- •
- all of the directors and director nominees of our general partner;
- •
- each named executive officer of our general partner; and
- •
- all directors, director nominees and officers of our general partner as a group.
Name and Address of Beneficial Owner(1)
| | Common Units to be Beneficially Owned
| | Percentage of Common Units to be Beneficially Owned
| | Subordinated Units to be Beneficially Owned
| | Percentage of Subordinated Units to be Beneficially Owned
| | Percentage of Total Common and Subordinated Units to be Beneficially Owned
| |
---|
Principal Stockholders: | | | | | | | | | | | |
Venoco | | 6,490,714 | | 41.6 | % | 5,339,286 | | 100 | % | 56.5 | % |
Director, Director Nominees and Officers: | | | | | | | | | | | |
Timothy Marquez | | — | | — | | — | | — | | — | |
William Schneider | | — | | — | | — | | — | | — | |
Mark DePuy | | — | | — | | — | | — | | — | |
Timothy Ficker | | — | | — | | — | | — | | — | |
Terry L. Anderson | | — | | — | | — | | — | | — | |
Charles H. Leonard | | — | | — | | — | | — | | — | |
J. Timothy Brittan | | — | | — | | — | | — | | — | |
All directors, director nominees and executive officers as a group (7 persons) | | — | | — | | — | | — | | — | |
- (1)
- Unless otherwise indicated, the address for the beneficial owner is 370 17th Street, Suite 3900, Denver, Colorado 80202.
116
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
After this offering, Venoco will own 6,490,714 common units and 5,339,286 subordinated units representing an aggregate 55.4% limited partner interest in us. In addition, our general partner will own a 2.0% general partner interest in us and the incentive distribution rights.
In connection with the closing of this offering, we will enter into a number of agreements with Venoco, our general partner and others, relating to our formation and operations. These agreements will not be the result of arm's-length negotiations, and they, and the transactions they contemplate, may have terms less favorable to us than could have been obtained from unaffiliated third parties.
Distributions and Payments to Our General Partner and Its Affiliates
The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of our partnership. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.
Formation Stage |
Consideration received by Venoco and its subsidiaries for the contribution of the Partnership Properties | | 6,490,714 common units; |
| | 5,339,286 subordinated units; |
| | 2% general partner interest in us; |
| | the incentive distribution rights; |
| | $45 million in cash from the proceeds of this offering; and |
| | $157.5 million in cash from the proceeds of borrowings we expect to make in connection with the closing of this offering; |
Reimbursement received by Venoco for expenses of the offering | | $2.0 million |
Operational Stage |
Distributions of available cash to our general partner and its affiliates | | We will generally make cash distributions 98% to our unitholders pro rata and 2% to our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 23% of the distributions above the highest target distribution level. |
| | Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, Venoco would receive distributions of approximately $20.7 million on its common and subordinated units. Please read "How We Will Make Cash Distributions." |
117
Payments to our general partner and its affiliates | | We will pay Venoco for the provision of various general and administrative services it performs for our benefit. For further information regarding the administrative fee, please read "—Agreements Relating to Our Operations—Administrative Services Agreement." |
Withdrawal or removal of our general partner | | If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read "The Partnership Agreement—Withdrawal or Removal of the General Partner." |
Liquidation Stage |
Liquidation | | Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances. Please read "How We Will Make Cash Distributions—Distributions of Cash upon Liquidation." |
Agreements Relating to Our Operations
At the closing of this offering, we will enter into several agreements with Venoco, our general partner and others to govern certain aspects of our operations and our relationship with those parties.
Administrative Services Agreement
We intend to enter into an administrative services agreement with Venoco and our general partner pursuant to which Venoco and its subsidiaries will perform administrative services for us such as accounting, business development, finance, land, legal, engineering, investor relations, management, marketing, information technology, insurance, government regulations, communications, regulatory, environmental and human resources. Venoco and its subsidiaries will be reimbursed for costs they incur in providing such services to us, including reimbursement for a proportionate amount of salary, bonus, incentive compensation and other amounts paid by Venoco and its subsidiaries to persons who perform services for us or on our behalf.
Omnibus Agreement
We will enter into an omnibus agreement with Venoco, our general partner and others that will address the following matters:
- •
- our obligation to reimburse Venoco for any insurance coverage expenses it incurs with respect to our business and operations;
- •
- Venoco's obligation to enter into an agreement with us, prior to exercising its right to conduct an EOR project, pursuant to which Venoco will agree to compensate us for lost production and reserves and any other interruption to our operations resulting from Venoco's exercise of its EOR right (please read "Business—Properties—Enhanced Oil Recovery");
- •
- Venoco's obligation to indemnify us for certain liabilities and our obligation to indemnify Venoco for certain liabilities; and
118
- •
- tax sharing pursuant to which we will pay Venoco for our share of income and other taxes to the extent that our results are included in a consolidated tax return filed by Venoco.
Any or all of the provisions of the omnibus agreement, other than the indemnification provisions described below, will be terminable by Venoco at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also terminate in the event of a change of control of us or our general partner.
Under the omnibus agreement, Venoco will indemnify us for one year after the closing of this offering against certain potential environmental claims, losses and expenses associated with the operation of the assets occurring before the closing date of this offering. Additionally, Venoco will indemnify us for losses attributable to title defects, retained assets and liabilities (including any pre-closing litigation relating to contributed assets) and income taxes attributable to pre-closing operations. Venoco's maximum liability for these indemnification obligations will not exceed $10 million and Venoco will not have any obligation under this indemnification until our aggregate losses exceed $500,000. Venoco will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after the closing date of this offering. We have agreed to indemnify Venoco against environmental liabilities related to our assets to the extent Venoco is not required to indemnify us. We also will indemnify Venoco for all losses attributable to the postclosing operations of the assets contributed to us, to the extent not subject to Venoco's indemnification obligations.
Venoco will also indemnify us for liabilities arising from litigation pending on our Beverly Hills property to the extent those liabilities are attributable to operations of the assets prior to the closing of this offering. Between June 2003 and April 2005, six lawsuits were filed against Venoco and certain other energy companies in Los Angeles County Superior Court by persons who attended Beverly Hills High School or who were or are citizens of Beverly Hills/Century City or visitors to that area during the time period running from the 1930s to date. There are approximately 1,000 plaintiffs (including plaintiffs in two related lawsuits in which Venoco has not been named) who claimed to be suffering from various forms of cancer or other illnesses, fear they may suffer from such maladies in the future, or are related to persons who have suffered from cancer or other illnesses. Plaintiffs alleged that exposure to substances in the air, soil and water that originated from either oil-field or other operations in the area were the cause of the cancers and other maladies. Venoco has owned an oil and natural gas facility adjacent to the school since 1995. For the majority of the plaintiffs, their alleged exposures occurred before Venoco acquired the facility. All cases were consolidated before one judge. Twelve "representative" plaintiffs were selected to have their cases tried first, while all of the other plaintiffs' cases were stayed. In November 2006, the judge entered summary judgment in favor of all defendants in the test cases, including Venoco. The judge dismissed all claims by the test case plaintiffs on the ground that they offered no evidence of medical causation between the alleged emissions and the plaintiffs' alleged injuries. Plaintiffs have appealed the ruling. Venoco vigorously defended the actions, and will continue to do so until they are resolved. Venoco also has defense and indemnity obligations to certain other defendants in the actions who have asserted claims for indemnity for events occurring after it acquired the property in 1995. In addition, certain defendants have made claims for indemnity for events occurring prior to 1995, which Venoco is disputing.
South Ellwood Agreements
At closing, we will also enter into joint operating and production handling agreements relating to the operation of the wells in the South Ellwood field in which we have an interest and the processing, treating and marketing of production from those wells. Under the agreements, we will pay Venoco a COPAS fee for each well Venoco operates for us and bear a part of Venoco's costs of operating its offshore platform and onshore facilities based on our share of total field production. We will also be
119
responsible for 23% of the abandonment costs associated with the wells in which we have an interest, platform Holly and Venoco's related onshore facilities.
Contribution Agreement
We intend to enter into a contribution agreement with Venoco and our general partner to effect, among other things, the transfer of the Partnership Properties from Venoco and its affiliates to us at the closing of this offering. We will hold title to these assets and will enter into an administrative services agreement with Venoco related to these assets as discussed above.
Procedures for Review, Approval and Ratification of Related Party Transactions
We anticipate that corporate governance guidelines will be adopted by the board of directors of our general partner and will provide that the board of directors of our general partner or its conflicts committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions.
We anticipate that the corporate governance guidelines will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board or directors of our general partner or its conflicts committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (1) whether there is an appropriate business justification for the transaction; (2) the benefits that accrue to us as a result of the transaction; (3) the terms available to unrelated third parties entering into similar transactions; (4) the impact of the transaction on a director's independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer); (5) the availability of other sources for comparable products or services; (6) whether it is a single transaction or a series of ongoing, related transactions; and (7) whether entering into the transaction would be consistent with our code of business conduct and ethics.
The policies described above have not yet been adopted, and as a result, the transactions described under "Certain Relationships and Related Party Transactions" were not reviewed under such polices, although had such polices been in place, review and approval of those transactions would have been required.
120
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Venoco) on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our limited partners. The board of directors or the conflicts committee of the board of directors of our general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any other partner, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner's fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty. Our general partner is responsible for identifying any such conflict of interest, and our general partner may choose to resolve the conflict of interest by any one of the methods described in the following sentence. Our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if the resolution of a conflict is:
- •
- approved by the conflicts committee, although our general partner is not obligated to seek such approval;
- •
- approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates, although our general partner is not obligated to seek such approval;
- •
- on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
- •
- fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
As required by our partnership agreement, the board of directors of our general partner will maintain a conflicts committee comprised of at least two independent directors. Our general partner may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest between us and our general partner or its affiliates. If our general partner seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. If a matter is submitted to the conflicts committee and the conflicts committee does not approve the matter, we will not proceed with the matter unless and until the matter has been modified in such a manner that the conflicts committee determines is fair and reasonable to us. Our general partner may, but is not required to, seek the approval of its resolution of a conflict of interest from unitholders or from the conflicts committee of its board of directors. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such
121
presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement provides that someone must act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.
Conflicts of interest could arise in the situations described below, among others.
Venoco and its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses. This could adversely affect our results of operations and cash available for distribution to our unitholders.
Neither our partnership agreement nor any other agreement between us, Venoco and our general partner will prohibit Venoco and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For example, Venoco owns interests in the South Ellwood field, the Hastings Complex and other parts of our area of operations that will not be conveyed to us. In addition, Venoco may acquire, develop or dispose of 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. Because we will be controlled by Venoco through its indirect ownership of our general partner, we will be able to compete for acquisition or development opportunities only to the extent that Venoco causes us to do so. As a result, competition from Venoco and its affiliates could adversely impact our results of operations and cash available for distribution.
Neither our partnership agreement nor any other agreement requires Venoco to pursue a business strategy that favors us. Venoco's directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of Venoco, which may be contrary to our interests.
Because certain of the directors and officers of our general partner are also directors and/or officers of Venoco, those persons have fiduciary duties to Venoco that may cause them to pursue business strategies that disproportionately benefit Venoco or which otherwise are not in our best interests.
Our partnership agreement limits the liability of our general partner and reduces its fiduciary duties and restricts the remedies available to our unitholders for actions that, without the limitation, might constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that limit the fiduciary duties required under state law and potential liability of our general partner. For example, our 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, and in a manner it believed to be in the best interests of our partnership;
- •
- generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be "fair and reasonable" to us, as determined by the general partner in good faith, and that, 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;
- •
- provides that our general partner and its officers and directors will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and
122
non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons 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
- •
- permits our general partner to make a number of decisions in its individual capacity rather than in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. Examples include decisions with respect to its right to reset the target distribution levels of its incentive distribution rights, its limited call right and the exercise of its voting and registration rights.
By purchasing a common unit, a common unitholder will agree to become bound by the provisions of the partnership agreement, including the provisions discussed above.
We will not have any employees and will rely on the employees of our general partner and its affiliates.
We will utilize a significant number of employees of Venoco to operate our business and provide us with general and administrative services. We will reimburse Venoco for allocated expenses of personnel who perform services for our benefit. Venoco will also conduct businesses and activities of its own in which we will have no economic interest. Accordingly, there could be material competition for the time and effort of the officers and employees who provide services to Venoco. The officers of our general partner will not be required to work full time on our affairs. These officers may devote significant time to the affairs of Venoco and will be compensated by Venoco for services rendered to them.
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:
- •
- the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurrence of any other obligations;
- •
- the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;
- •
- the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;
- •
- the negotiation, execution and performance of any contracts, conveyances or other instruments;
- •
- the distribution of our cash;
- •
- the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;
- •
- the maintenance of insurance for our benefit and the benefit of our partners;
- •
- the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other entities;
123
- •
- the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;
- •
- the indemnification of any person against liabilities and contingencies to the extent permitted by law;
- •
- the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and
- •
- the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.
Our partnership agreement provides that our general partner must act in "good faith" when making decisions on our behalf. The partnership agreement further provides that in order for a determination by our general partner to be made in "good faith," our general partner must believe that the determination is in our best interests. Please read "The Partnership Agreement—Voting Rights" for information regarding matters that require unitholder approval.
Our general partner determines the amount and timing of acquisitions and divestitures, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:
- •
- amount and timing of acquisitions and divestitures;
- •
- capital expenditures;
- •
- borrowings;
- •
- the issuance of additional units; and
- •
- the creation, reduction or increase of reserves in any quarter.
In addition, our general partner may use $20 million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and the general partner. These actions may also facilitate the conversion of subordinated units into common units. Please read "How We Will Make Cash Distributions."
In addition, our general partner may cause us or our affiliates to borrow funds, including borrowings that have the purpose or effect of enabling our general partner or its affiliates to receive distributions on any subordinated units or the incentive distribution rights, or hastening the expiration of the subordination period. For example, if we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds in order to make such a distribution on all outstanding units. Please read "How We Will Make Cash Distributions—Subordination Period." In addition, our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. However, our general partner and its affiliates may not borrow funds from us, our operating company or its operating subsidiaries.
124
Our partnership agreement does not restrict our general partner from causing us to pay it or Venoco or their respective affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us, including reimbursements for costs they incur in managing and operating us. Our general partner may also enter into additional contractual arrangements with Venoco on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and Venoco, on the other hand, that will be in effect as of the closing of this offering will be the result of arm's-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and Venoco that are entered into following the closing of this offering will not be required to be negotiated on an arm's-length basis, although, in some circumstances, the conflicts committee of our general partner may review such agreements, contracts or arrangements. Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.
Our general partner and its affiliates will have no obligation to permit us to use any facilities or assets of our general partner or its affiliates, except as may be provided in contracts entered into specifically dealing with that use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.
Our general partner intends to limit its liability regarding our obligations.
Our general partner intends to limit its liability under contractual arrangements so that the other party has recourse only to our assets, and not against our general partner or its assets. The partnership agreement provides that no action taken by our general partner to limit its liability will constitute a breach of its fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.
Our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units.
Our general partner may exercise its right to call and purchase common units as provided in the partnership agreement or assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read "The Partnership Agreement—Limited Call Right."
Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.
No agreement between us on the one hand, and our general partner, on the other, will grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner in our favor.
Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm's-length negotiations.
Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between us, on the one hand,
125
and our general partner and its affiliates, on the other, are or will be the result of arm's-length negotiations.
Our general partner will determine, in good faith, the terms of any of these transactions entered into after the sale of the common units offered in this offering.
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of our general partner or our unitholders. This may result in lower distributions to our common unitholders in certain situations.
Our general partner has the right, at a time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (23%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to specified priorities with respect to our distributions equal to those of the common units, and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner incentive distribution rights. Please read "How We Will Make Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."
Fiduciary Duties
Our general partner is accountable to us and our unitholders as a fiduciary. The fiduciary duties our general partner owes to us and our unitholders are prescribed by law and the partnership agreement. The Delaware Revised Uniform Limited Partnership Act, which we refer to in this
126
prospectus as the Delaware Act, provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.
Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that our general partner might otherwise owe us and our unitholders. We have adopted these restrictions to allow our general partner and Venoco to engage in transactions with us that would otherwise be prohibited by state law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner's board of directors will have fiduciary duties to manage our general partner in a manner beneficial to its owners, as well as to us and our unitholders. Without these modifications, the general partner's ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our common unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:
State law fiduciary duty standards | | Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner of a Delaware limited partnership to demonstrate the entire fairness of any action or transaction where a conflict of interest is present. |
Rights and remedies of unitholders | | The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include action against a general partner for breach of its fiduciary duties or of a partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners. |
127
Partnership agreement modified standards | | Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties under Delaware law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, and not in its sole discretion, it must act in "good faith" and will not be subject to any other standard. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held. |
| | In recent cases, the Delaware Supreme Court discussed the meaning of good faith and stated that a failure to act in good faith may be shown, for instance, where a fiduciary intentionally: |
| | • | | acts with a purpose other than that of advancing the best interests of the company; |
| | • | | violates applicable law; or |
| | • | | fails to act in the face of a known duty to act, demonstrating a conscious disregard for his duties. |
| | In instances where the question is whether a fiduciary acted with a purpose other than that of advancing the best interests of the company, the Delaware Supreme Court has held that a fiduciary acts in good faith where the actions were taken with the subjective belief that those actions were in the best interests of the company. |
| | When our general partner is acting in its "sole discretion" or "discretion" or under a grant of similar authority or latitude, as opposed to in its capacity as our general partner, it (1) is entitled to consider only such interests and factors as it desires (including its own), (2) has no duty or obligation to consider any interest of, or factors affecting, us or any limited partner, and (3) is not required to fulfill any other standard imposed by our partnership agreement, the Delaware Act or any other law, rule or regulation. These standards reduce the obligations to which our general partner would otherwise be held. |
128
| | In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and our officers and directors will not be liable for monetary damages to us, our unitholders or assignees for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or our officers and directors acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with the knowledge that such conduct was unlawful. |
Special provisions regarding affiliated transactions | | Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest, which do not involve a vote of unitholders or which are not approved by the conflicts committee of the board of directors of our general partner must be: |
| | • | | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| | • | | "fair and reasonable" to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us). |
| | If our general partner does not seek approval from the conflicts committee and the board of directors of our general partner determines that the resolution of the conflict of interest satisfies either of the standards set forth in the bullet points above, then (1) the resolution will be deemed fair and reasonable to us and will be conclusive and binding on us and our unitholders and (2) in any proceeding brought by or on behalf of any unitholder or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming the presumptions that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith, and that the resolution of the conflict of interest was fair and reasonable to us. These standards reduce the obligations to which our general partner would otherwise be held. |
In order to become one of our limited partners, a unitholder is required to agree to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner or assignee to sign a partnership agreement does not render the partnership agreement unenforceable against that person. By purchasing a common unit, you will be admitted as a limited partner and will be deemed to be bound by all of the terms of our partnership agreement.
129
Our partnership agreement provides that we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law. This means, among other things, that we must indemnify our general partner or these other persons against expenses (including attorneys' fees), judgments, penalties, fines and amounts paid in settlement that are actually and reasonably incurred in an action, suit or proceeding by reason of our general partner's or the person's status as an indemnitee. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read "The Partnership Agreement—Indemnification."
130
DESCRIPTION OF THE COMMON UNITS
The Units
The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in partnership distributions, please read this section and "Our Cash Distribution Policy and Restrictions on Distributions." For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read "The Partnership Agreement."
Transfer Agent and Registrar
Duties. Computershare Trust Company, Inc. will serve as registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:
- •
- surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;
- •
- special charges for services requested by a common unitholder; and
- •
- other similar fees or charges.
There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.
Resignation or Removal. The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.
Transfer of Common Units
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:
- •
- represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;
- •
- automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and
- •
- gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.
A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.
131
We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder's rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.
Common units are securities and are transferable according to the laws governing transfers of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.
Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.
132
THE PARTNERSHIP AGREEMENT
The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.
We summarize the following provisions of our partnership agreement elsewhere in this prospectus:
- •
- with regard to distributions of available cash, please read "How We Will Make Cash Distributions;"
- •
- with regard to the fiduciary duties of our general partner, please read "Conflicts of Interest and Fiduciary Duties;"
- •
- with regard to the transfer of common units, please read "Description of the Common Units—Transfer of Common Units;" and
- •
- with regard to allocations of taxable income and taxable loss, please read "Material Tax Consequences."
Organization and Duration
Our partnership was formed on September 25, 2007 and will have a perpetual existence.
Purpose
Our purpose under the partnership agreement is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.
Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of acquiring, developing, producing, marketing and transporting oil and natural gas properties, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.
Power of Attorney
Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our formation, qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.
Cash Distributions
Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read "How We Will Make Cash Distributions."
133
Capital Contributions
Unitholders are not obligated to make additional capital contributions, except as described below under "—Limited Liability."
Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2% general partner interest if we issue additional units. Except in connection with the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, our general partner's 2% general partner interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.
Voting Rights
The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a "unit majority" require:
- •
- during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and
- •
- after the subordination period, the approval of a majority of the common units and Class B units, if any, voting as a single class.
In voting their common, Class B and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.
Issuance of additional units | | No approval right. |
Amendment of the partnership agreement | | Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read "—Amendment of the Partnership Agreement." |
Merger of our partnership or the sale of all or substantially all of our assets | | Unit majority in certain circumstances. Please read "—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets." |
Dissolution of our partnership | | Unit majority. Please read "—Termination and Dissolution." |
Continuation of our partnership upon dissolution | | Unit majority. Please read "—Termination and Dissolution." |
Withdrawal of the general partner | | Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and their affiliates, is required for the withdrawal of our general partner prior to December 31, 2018 in a manner that would cause a dissolution of our partnership. Please read "—Withdrawal or Removal of the General Partner." |
134
Removal of the general partner | | Not less than 662/3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read "—Withdrawal or Removal of the General Partner." |
Transfer of the general partner interest | | Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets, to such person. The approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to December 31, 2018. Thereafter, our general partner may transfer all or a portion of its general partner interest in us without a vote of our unitholders. Please read "—Transfer of General Partner Interest." |
Transfer of incentive distribution rights | | Except for transfers to an affiliate or another person as part of our general partner's merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in such holder, the approval of a majority of the common units, excluding common units held by the general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to December 31, 2018. Please read "—Transfer of Ownership Interests in the General Partner—Transfer of Incentive Distribution Rights." |
Transfer of ownership interests in our general partner | | No approval required at any time. Please read "—Transfer of Ownership Interests in the General Partner." |
Limited Liability
Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:
- •
- to remove or replace the general partner;
- •
- to approve some amendments to the partnership agreement; or
- •
- to take other action under the partnership agreement;
constituted "participation in the control" of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as the general partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither the partnership agreement nor the Delaware Act specifically provides for legal recourse against the general partner if a
135
limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.
Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.
Our subsidiaries conduct business in two states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as an owner of the operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.
Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace the general partner, to approve some amendments to the partnership agreement, or to take other action under the partnership agreement constituted "participation in the control" of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as the general partner under the circumstances. We will operate in a manner that the general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.
Issuance of Additional Securities
Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.
It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.
In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity securities, which may effectively rank senior to the common units.
136
Upon issuance of additional partnership securities (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our general partner's incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2% general partner interest in us. Except in connection with the issuance of common units upon exercise by the underwriters of their option to purchase additional common units, our general partner's 2% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.
Amendment of the Partnership Agreement
General. Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
Prohibited Amendments. Generally, no amendment may be made that would:
- •
- have the effect of reducing the voting percentage of outstanding units required to take any action under the provisions of our partnership agreement;
- •
- enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or
- •
- enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.
The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units voting together as a single class (including units owned by our general partner and its affiliates). At the closing of the offering, our general partner, its owners and their affiliates will own approximately 41.6% of the outstanding common units and all of the outstanding subordinated units (56.5% of the outstanding units as a single class), assuming the underwriters do not exercise their option to purchase additional common units.
No Unitholder Approval. Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner or assignee to reflect:
- •
- a change in our name, the location of our principal place of our business, our registered agent or our registered office;
137
- •
- the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;
- •
- a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;
- •
- an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or "plan asset" regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;
- •
- an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or rights to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:
- •
- the adjustments of the minimum quarterly distribution, first target distribution and second target distribution in connection with the reset of our general partner's incentive distribution rights as described under "How We Will Make Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels;" or
- •
- the implementation of the provisions relating to our general partner's right to reset its incentive distribution rights in exchange for Class B units; and
- •
- any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;
- •
- any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;
- •
- an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;
- •
- any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;
- •
- a change in our fiscal year or taxable year and related changes;
- •
- conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or
- •
- any other amendments substantially similar to any of the matters described in the clauses above.
In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner or assignee if our general partner determines, at its option, that those amendments:
- •
- do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;
138
- •
- are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;
- •
- are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted for trading;
- •
- are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or
- •
- are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.
Opinion of Counsel and Unitholder Approval. Our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.
In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets
A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.
In addition, the partnership agreement generally prohibits our general partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction, and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.
If the conditions specified in the partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that
139
conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters, and the governing instruments of the new entity provide the limited partners and the general partner with the same rights and obligations as contained in the partnership agreement. The unitholders are not entitled to dissenters' rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.
Termination and Dissolution
We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:
- •
- the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;
- •
- there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;
- •
- the entry of a decree of judicial dissolution of our partnership; or
- •
- the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.
Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:
- •
- the action would not result in the loss of limited liability of any limited partner; and
- •
- neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.
Liquidation and Distribution of Proceeds
Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate to liquidate our assets and apply the proceeds of the liquidation as described in "How We Will Make Cash Distributions—Distributions of Cash upon Liquidation." The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.
Withdrawal or Removal of the General Partner
Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to December 31, 2018 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by the general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after December 31, 2018, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days' written notice, and that withdrawal will not constitute a
140
violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days' notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates other than the general partner and its affiliates. In addition, the partnership agreement permits our general partner in some instances to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read "—Transfer of General Partner Interest" and "—Transfer of Ownership Interests in the General Partner—Transfer of Incentive Distribution Rights."
Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority, voting as separate classes, may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read "—Termination and Dissolution."
Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 662/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units and Class B units, if any, voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than 331/3% of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner's removal. At the closing of this offering, our general partner, its owners and their affiliates will own 56.5% of the outstanding common and subordinated units.
Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by the general partner and its affiliates are not voted in favor of that removal:
- •
- the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
- •
- any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
- •
- our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.
In the event of the removal of our general partner under circumstances where cause exists or the withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where a general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an
141
expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner's general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.
Transfer of General Partner Interest
Except for transfer by our general partner of all, but not less than all, of its general partner interest to:
- •
- an affiliate of our general partner (other than an individual); or
- •
- another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,
our general partner may not transfer all or any of its general partner interest to another person prior to December 31, 2018 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. Thereafter, our general partner may transfer all or any of its general partner interest to another person without the approval of unitholders. As a condition of any transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement, and furnish an opinion of counsel regarding limited liability and tax matters.
Our general partner and its affiliates may at any time, transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.
Transfer of Ownership Interests in the General Partner
At any time, Venoco may sell or transfer all or part of its membership interests in our general partner to an affiliate or third party without the approval of our unitholders.
Transfer of Incentive Distribution Rights
Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interest in the holder or the sale of all or substantially all of its assets to, that entity without the prior approval of the unitholders. Prior to December 31, 2018, other transfers of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after December 31, 2018, the incentive distribution rights will be freely transferable.
Change of Management Provisions
Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or otherwise change our management. If any
142
person or group other than our general partner or Venoco acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.
Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:
- •
- the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;
- •
- any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and
- •
- our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.
Limited Call Right
If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10 but not more than 60 days notice. The purchase price in the event of this purchase is the greater of:
- •
- the average offering price of common units for the 20 trading days preceding the purchase; and
- •
- the highest cash price paid by either of our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the purchase.
As a result of our general partner's right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read "Material Tax Consequences—Disposition of Common Units."
The general partner's right to purchase common units pursuant to this limited call right will be subject to the general partner's compliance with applicable securities and other laws.
Meetings; Voting
Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Units that are owned by Non-Eligible Holders will be voted by our general partner, and our general partner will distribute the votes on those units in the same ratios as the votes of limited partners on other units are cast.
Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be
143
taken either at a meeting of the unitholders or, if authorized by our general partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting. Special meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.
Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read "—Issuance of Additional Securities." However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes except that such units may be considered outstanding for purposes of the withdrawal of our general partner. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units and Class B units as a single class.
Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.
Status as Limited Partner
By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Except as described under "—Limited Liability," the common units will be fully paid, and unitholders will not be required to make additional contributions.
Non-Eligible Holders; Redemption
To comply with certain U.S. laws relating to the ownership of interests in oil and natural gas leases on federal lands and certain FERC requirements, transferees are required to fill out a properly completed transfer application certifying, and our general partner, acting on our behalf, may at any time require each unitholder to re-certify, that the unitholder is an Eligible Holder. As used in our partnership agreement, an Eligible Holder means a person or entity qualified to hold an interest in oil and natural gas leases on federal lands, and a person or entity subject to U.S. federal income taxation on our income or entities not subject to such taxation as long as all of the entity's owners are subject to such taxation.
With respect to federal leases, an Eligible Holder must be:
- •
- 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;
144
- •
- 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. This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.
With respect to FERC requirements, an Eligible Holder must be:
- •
- an individual or entity subject to United States federal income taxation on the income generated by us; or
- •
- an entity not subject to United States federal income taxation on the income generated by us, so long as all of the entity's owners are subject to such taxation.
If a transferee or unitholder, as the case may be, fails to furnish:
- •
- a transfer application containing the required certification,
- •
- a re certification containing the required certification within 30 days after request, or
- •
- provides a false certification,
then, as the case may be, such transfer will be void or we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, the units held by such unitholder will not be entitled to any allocations of income or loss, distributions or voting rights.
The purchase price will be paid in cash or delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date. Any such promissory note will also be unsecured and shall be subordinated to the extent required by the terms of our other indebtedness.
Indemnification
Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:
- •
- our general partner;
- •
- any departing general partner;
- •
- any person who is or was an affiliate of or owner of an equity interest in a general partner or any departing general partner;
- •
- any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;
- •
- any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and
- •
- any person designated by our general partner.
145
Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our general partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance or be insured under policies obtained by the general partner or any affiliate of the general partner against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.
Reimbursement of Expenses
Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The general partner is entitled to determine in good faith the expenses that are allocable to us.
We intend to enter into an administrative services agreement with Venoco, our general partner and certain of their affiliates, pursuant to which we will agree to indemnify Venoco for certain liabilities arising after the closing of this offering and one of Venoco's subsidiaries will operate our properties and perform administrative services for us such as accounting, marketing, corporate development, finance, land, legal and engineering in exchange for reimbursement from us. For a description of the fees and expenses that we will pay pursuant to this agreement, please read "Certain Relationships and Related Party Transactions."
Books and Reports
Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.
We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.
We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.
Right to Inspect Our Books and Records
Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:
- •
- a current list of the name and last known address of each partner;
- •
- a copy of our tax returns;
146
- •
- information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;
- •
- copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;
- •
- information regarding the status of our business and financial condition; and
- •
- any other information regarding our affairs as is just and reasonable.
Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential or which the general partner determines is burdensome to provide and not necessary to for a limited partner to evaluate our business or financial condition.
Registration Rights
Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or Venoco, our officers and directors or any of their respective affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Venoco Acquisition Company GP, LLC as general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and a structuring fee. Please read "Units Eligible for Future Sale."
147
UNITS ELIGIBLE FOR FUTURE SALE
After the sale of the common units offered by this prospectus, and assuming the underwriters do not exercise their option to purchase additional common units, Venoco and its affiliates will hold an aggregate of 6,490,714 common units and 5,339,286 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.
The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an "affiliate" of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:
- •
- 1% of the total number of the securities outstanding; or
- •
- the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.
Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale, and who has beneficially owned his Rule 144 restricted common units for at least six months, would be entitled to sell those common units under Rule 144 subject only to the current public information requirement. After beneficially owning Rule 144 restricted common units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely resell those common units without regard to any of the conditions of Rule 144.
Our partnership agreement does not restrict our ability to issue any partnership securities at any time. Any issuance of additional common units or other partnership securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read "The Partnership Agreement—Issuance of Additional Securities."
Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights will allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and Venoco will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and a structuring fee. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.
We, our general partner and its affiliates and the directors and executive officers of our general partner have agreed not to sell any common units our general partner beneficially owns for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read "Underwriting."
148
MATERIAL TAX CONSEQUENCES
This section is a discussion of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to us, insofar as it relates to legal conclusions with respect to matters of United States federal income tax law. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to "us" or "we" are references to Venoco Acquisition Company, L.P. and our operating subsidiaries.
The following discussion does not address all federal income tax matters that affect us or the unitholders. Furthermore, this discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of our common units.
No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel's best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.
All statements regarding matters of law and legal conclusions set forth below, but not factual matters unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.
For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues:
- (1)
- the treatment of a common unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read "—Tax Consequences of Common Unit Ownership—Treatment of Short Sales");
- (2)
- whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read "—Disposition of Common Units—Allocations Between Transferors and Transferees");
- (3)
- whether percentage depletion will be available to a common unitholder or the extent of the percentage depletion deduction available to any common unitholder (please read "—Tax Treatment of Operations—Depletion Deductions");
- (4)
- whether the deduction related to U.S. production activities will be available to a common unitholder or the extent of such deduction to any common unitholder (please read "—Tax Treatment of Operations—Deduction for U.S. Production Activities"); and
149
- (5)
- whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read "—Tax Consequences of Common Unit Ownership—Section 754 Election" and "—Uniformity of Common Units").
Partnership Status
A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner in a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partner, unless the amount of cash distributed to him is in excess of his adjusted tax basis in his partnership interest.
Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the "Qualifying Income Exception," exists with respect to publicly traded partnerships 90% or more of the gross income of which for every taxable year consists of "qualifying income." Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including oil, gas, and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.
No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate "qualifying income" under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings, court decisions and the representations described below, we will be classified as a partnership, and each of our operating subsidiaries will be disregarded as an entity separate from us for U.S. federal income tax purposes.
In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us. The representations made by us upon which Vinson & Elkins L.L.P. has relied include:
- (1)
- Neither we, nor any of our operating subsidiaries, have elected or will elect to be treated as a corporation;
- (2)
- For each taxable year, more than 90% of our gross income will be income that Vinson & Elkins L.L.P. has opined or will opine is "qualifying income" within the meaning of Section 7704(d) of the Internal Revenue Code; and
- (3)
- Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, gas, or products thereof that are held or to be held by the us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.
If we do not meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, in which case the IRS
150
may also require us to make adjustments with respect to our unitholders or pay other amounts, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we do not meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.
If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss, and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a common unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the common unitholder's tax basis in his common units, and taxable capital gain after the common unitholder's tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a common unitholder's cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the common units.
The remainder of the discussion below is based on Vinson & Elkins L.L.P.'s opinion that we will be classified as a partnership for federal income tax purposes.
Limited Partner Status
Unitholders who become limited partners of Venoco Acquisition Company, L.P. will be treated as partners of Venoco Acquisition Company, L.P. for federal income tax purposes. Also:
- •
- assignees who are awaiting admission as partners, and
- •
- unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units
will be treated as partners of Venoco Acquisition Company, L.P. for federal income tax purposes.
Because there is no direct or indirect controlling authority addressing the federal tax treatment of assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who do not execute and deliver transfer applications, the opinion of Vinson & Elkins L.L.P. does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.
A beneficial owner of common units whose common units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those common units for federal income tax purposes. Please read "—Tax Consequences of Common Unit Ownership—Treatment of Short Sales."
Items of our income, gain, loss, or deduction would not appear to be reportable by a common unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a common unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to the tax consequences of holding units in us.
151
The references to "unitholders" in the discussion that follows are to persons who are treated as partners in Venoco Acquisition Company, L.P. for U.S. federal income tax purposes.
Tax Consequences of Common Unit Ownership
Flow-Through of Taxable Income
We will not pay any federal income tax. Instead, each common unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a common unitholder even if he has not received a cash distribution. Each common unitholder will be required to include in income his allocable share of our income, gain, loss and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.
Treatment of Distributions
Distributions made by us to a common unitholder generally will not be taxable to him for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Cash distributions made by us to a common unitholder in an amount in excess of his tax basis in his common units generally will be considered to be gain from the sale or exchange of those common units, taxable in accordance with the rules described under "—Disposition of Common Units" below. To the extent that cash distributions made by us cause a common unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses."
Any reduction in a common unitholder's share of our liabilities for which no partner bears the economic risk of loss, known as "nonrecourse liabilities," will be treated as a distribution of cash to that common unitholder. To the extent our distributions cause a unitholder's "at-risk" amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read "—Limitations on Deductibility of Losses." A decrease in a common unitholder's percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a common unitholder, regardless of his tax basis in his common units, if the distribution reduces the common unitholder's share of our "unrealized receivables," including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated "inventory items," both as defined in Section 751 of the Internal Revenue Code, and collectively, "Section 751 Assets." To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the common unitholder's realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the common unitholder's tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.
Ratio of Taxable Income to Distributions
We estimate that a purchaser of our common units in this offering who holds those common units from the date of closing of this offering through the record date for distributions for the period ending March 31, 2011, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than % of the cash distributed to the common unitholder with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from
152
operations will approximate the amount required to make the minimum quarterly distributions on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:
- •
- gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distribution on all units; or
- •
- we make a future offering of units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depletion, depreciation or amortization for federal income tax purposes or that is depletable, depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.
Basis of Common Units
A common unitholder's initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That tax basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That tax basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A common unitholder's share of our nonrecourse liabilities will generally be based on his share of our profits. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
Limitations on Deductibility of Losses
The deduction by a common unitholder of his share of our losses will be limited to his tax basis in his common units and, in the case of an individual common unitholder, estate, trust or a corporate common unitholder (if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals) or some tax-exempt organizations to the amount for which the common unitholder is considered to be "at risk" with respect to our activities, if that amount is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a common unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholder's tax basis in his common units. Upon the taxable disposition of a common unit, any gain recognized by a common unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the risk limitation in excess of that gain would no longer be utilizable.
153
In general, a common unitholder will be at risk to the extent of his tax basis in his common units, excluding any portion of that tax basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to the common unitholder or can look only to the common units for repayment. A common unitholder's at-risk amount will increase or decrease as the tax basis of the common unitholder's common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a common unitholder's at-risk amount will decrease by the amount of the common unitholder's depletion deductions and will increase to the extent of the amount by which the common unitholder's percentage depletion deductions with respect to our property exceed the common unitholder's share of the tax basis of that property.
The at-risk limitation applies on an activity-by-activity basis, and in the case of gas and oil properties, each property is treated as a separate activity. Thus, a taxpayer's interest in each oil or gas property is generally required to be treated separately so that a loss from any one property would be limited to the at-risk amount for that property and not the at-risk amount for all the taxpayer's gas and oil properties. It is uncertain how this rule is implemented in the case of multiple gas and oil properties owned by a single entity treated as a partnership for federal income tax purposes. However, for taxable years ending on or before the date on which further guidance is published, the IRS will permit aggregation of oil or gas properties we own in computing a common unitholder's at-risk limitation with respect to us. If a common unitholder were required to compute his at-risk amount separately with respect to each oil or gas property we own, he might not be allowed to utilize his share of losses or deductions attributable to a particular property even though he has a positive at-risk amount with respect to his common units as a whole.
In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitation generally provides that individuals, estates, trusts and some closely held corporations and personal service corporations are permitted to deduct losses from passive activities, which are generally defined as trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer's income from those passive activities. The passive loss limitation is applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments, a common unitholder's investments in other publicly traded partnerships, or a common unitholder's salary or active business income. If we dispose of all or only a part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Passive losses that are not deductible because they exceed a common unitholder's share of income we generate may be deducted by the common unitholder in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at-risk rules and the tax basis limitation.
A common unitholder's share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.
154
Limitations on Interest Deductions
The deductibility of a non-corporate taxpayer's "investment interest expense" is generally limited to the amount of that taxpayer's "net investment income." Investment interest expense includes:
- •
- interest on indebtedness properly allocable to property held for investment;
- •
- our interest expense attributable to portfolio income; and
- •
- the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.
The computation of a common unitholder's investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a common unit.
Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders for purposes of the investment interest expense deduction limitation. In addition, the common unitholder's share of our portfolio income will be treated as investment income.
Entity-Level Collections
If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any common unitholder or any former common unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the common unitholder on whose behalf the payment was made. If the payment is made on behalf of a common unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a common unitholder in which event the common unitholder would be required to file a claim in order to obtain a credit or refund.
Allocation of Income, Gain, Loss and Deduction
In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, the loss will be allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances.
Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Internal Revenue Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as "Contributed Property." These "Section 704(c) Allocations" are required to eliminate the difference between a partner's "book" capital account, credited with the fair market value of Contributed Property, and the "tax" capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the "Book-Tax Disparity." The effect of these allocations to a common unitholder who purchases
155
common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In the event we issue additional common units or engage in certain other transactions in the future, "Reverse Section 704(c) Allocations," similar to the Section 704(c) Allocations described above, will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the "book" basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the common unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.
An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a common unitholder's share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a common unitholder's share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:
- •
- his relative contributions to us;
- •
- the interests of all the partners in profits and losses;
- •
- the interest of all the partners in cash flow; and
- •
- the rights of all the partners to distributions of capital upon liquidation.
Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in "—Section 754 Election," "—Uniformity of Common Units" and "—Disposition of Common Units—Allocations Between Transferors and Transferees," allocations under our partnership agreement will be given effect for federal income tax purposes in determining a common unitholder's share of an item of income, gain, loss or deduction.
Treatment of Short Sales
A common unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:
- •
- none of our income, gain, loss or deduction with respect to those common units would be reportable by the common unitholder;
- •
- any cash distributions received by the common unitholder with respect to those common units would be fully taxable; and
- •
- all of these distributions would appear to be ordinary income.
Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a common unitholder whose common units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read "—Disposition of Common Units—Recognition of Gain or Loss."
156
Alternative Minimum Tax
Each common unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult their tax advisors with respect to the impact of an investment in our common units on their liability for the alternative minimum tax.
Tax Rates
In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than twelve months at the time of disposition. The capital gains tax rate is scheduled to remain at 15% for years 2008-2010, and then increase to 20% beginning January 1, 2011.
Section 754 Election
We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a common unit purchaser's tax basis in our assets ("inside basis") under Section 743(b) of the Internal Revenue Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases common units directly from us, and it belongs only to the purchaser and not to other unitholders. Please also read, however, "—Allocation of Income, Gain, Loss and Deduction" above. For purposes of this discussion, a common unitholder's inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets ("common basis") and (2) his Section 743(b) adjustment to that tax basis.
Where the remedial allocation method is adopted (which we will generally adopt as to all of our properties), the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property's unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. If we elect a method other than the remedial method, the depreciation and amortization methods and useful lives associated with the Section 743(b) adjustment, therefore, may differ from the methods and useful lives generally used to depreciate the inside basis in such properties. Under our partnership agreement, we are authorized to take a position to preserve the uniformity of common units even if that position is not consistent with these and any other Treasury Regulations. Please read "—Uniformity of Common Units."
Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property's unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To
157
the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring common units in the same month would receive depreciation or amortization, whether attributable to basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read "—Uniformity of Common Units." A common unitholder's tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual's income tax return) so that any position we take that understates deductions will overstate the common unitholder's basis in his common units, which may cause the common unitholder to understate gain or overstate loss on any sale of such common units. Please read "—Disposition of Common Units—Recognition of Gain or Loss." The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the common units. If such a challenge were sustained, the gain from the sale of common units might be increased without the benefit of additional deductions.
A Section 754 election is advantageous if the transferee's tax basis in his common units is higher than the common units' share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee's tax basis in his common units is lower than those common units' share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the common units may be affected either favorably or unfavorably by the election. A tax basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial tax basis reduction. Generally a built-in loss or a tax basis reduction is substantial if it exceeds $250,000.
The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of common units may be allocated more income than he would have been allocated had the election not been revoked.
Tax Treatment of Operations
Accounting Method and Taxable Year
We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each common unitholder will be required to include in his income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a common unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his common units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in
158
income for his taxable year, with the result that he will be required to include in his taxable income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read "—Disposition of Common Units—Allocations Between Transferors and Transferees."
Depletion Deductions
Subject to the limitations on deductibility of losses discussed above (please read "—Limitations on Deductibility of Losses"), unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our natural gas and oil interests. Although the Internal Revenue Code requires each common unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes. Each common unitholder, however, remains responsible for calculating his own depletion allowance and maintaining records of his share of the adjusted tax basis of the underlying property for depletion and other purposes.
Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Internal Revenue Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the common unitholder's gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the common unitholder from the property for each taxable year, computed without the depletion allowance. A common unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the common unitholder's average daily production of domestic oil, or the gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between gas and oil production, with 6,000 cubic feet of domestic gas production regarded as equivalent to one barrel of oil. The 1,000-barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.
In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a common unitholder's total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the common unitholder's total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.
Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the common unitholder's share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and thousand cubic feet, or Mcf, of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the common unitholder's share of the total adjusted tax basis in the property.
All or a portion of any gain recognized by a common unitholder as a result of either the disposition by us of some or all of our natural gas and oil interests or the disposition by the common unitholder of some or all of his common units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the tax basis
159
of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.
The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each common unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective common unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.
Deductions for Intangible Drilling and Development Costs
We will elect to currently deduct intangible drilling and development costs (IDCs). IDCs generally include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.
Although we will elect to currently deduct IDCs, each common unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a common unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount in respect of those IDCs will result for alternative minimum tax purposes.
Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An "integrated oil company" is a taxpayer that has economic interests in oil or gas properties and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an "independent producer" that is not subject to these IDC deduction limits, a common unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of gas) on average for any day during the taxable year or in the retail marketing of gas and oil products exceeding $5 million per year in the aggregate.
IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted tax basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a common unitholder of interests in us. Recapture is generally determined at the common unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
160
Deduction for U.S. Production Activities
Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such common unitholder, but not to exceed 50% of such unitholder's IRS Form W-2 wages paid or allocated to him for the taxable year allocable to domestic production gross receipts. The percentages are 6% for qualified production activities income generated in the years 2007, 2008, and 2009; and 9% thereafter.
Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, grown or extracted in whole or in significant part by the taxpayer in the United States.
For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each common unitholder will aggregate his share of the qualified production activities income allocated to him from us with the common unitholder's qualified production activities income from other sources. Each common unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are taken into account only if and to the extent the common unitholder's share of losses and deductions from all of our activities is not disallowed by the tax basis rules, the at-risk rules or the passive activity loss rules. Please read "—Tax Consequences of Common Unit Ownership—Limitations on Deductibility of Losses."
The amount of a common unitholder's Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages actually or deemed paid by the common unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each common unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the common unitholder's allocable share of our wages that are deducted in arriving at qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders. Moreover, legislation passed by the House of Representatives and pending in the Senate would deny the Section 199 deduction with respect to certain oil and gas production activities income. We are unable to predict whether this proposed legislation will ultimately be enacted.
This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each common unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective common unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.
Lease Acquisition Costs. The cost of acquiring gas and oil lease or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read "—Depletion Deductions."
Geophysical Costs. The cost of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deducted ratably over a 24-month period beginning on the date that such expense is paid or incurred.
161
Operating and Administrative Costs. Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses that are reasonable in amount.
Tax Basis, Depreciation and Amortization
The tax basis of our tangible assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our general partner, and (ii) any other offering will be borne by our unitholders as of that time. Please read "—Tax Consequences of Common Unit Ownership—Allocation of Income, Gain, Loss and Deduction."
To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. If we determine not to adopt the remedial method of allocation with respect to any difference between the tax basis and the fair market value of goodwill immediately prior to this or any future offering, we may not be entitled to any amortization deductions with respect to any goodwill conveyed to us on formation or held by us at the time of any future offering. Please read "—Uniformity of Common Units." Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.
If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a common unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read "—Tax Consequences of Common Unit Ownership—Allocation of Income, Gain, Loss and Deduction" and "—Disposition of Common Units—Recognition of Gain or Loss."
The costs we incur in selling our common units (called "syndication expenses") must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.
Valuation and Tax Basis of Our Properties
The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or tax basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.
162
Disposition of Common Units
Recognition of Gain or Loss
Gain or loss will be recognized on a sale of common units equal to the difference between the common unitholder's amount realized and the common unitholder's tax basis for the common units sold. A common unitholder's amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a common unitholder's share of our nonrecourse liabilities, the gain recognized on the sale of common units could result in a tax liability in excess of any cash received from the sale.
Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a common unitholder's tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the common unitholder's tax basis in that common unit, even if the price received is less than his original cost.
Except as noted below, gain or loss recognized by a common unitholder, other than a "dealer" in common units, on the sale or exchange of a common unit held for more than one year will generally be taxable as long-term capital gain or loss. Capital gain recognized by an individual on the sale of common units held more than twelve months is scheduled to be taxed at a maximum rate of 15% through December 31, 2010. However, a portion of this gain or loss, which may be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to "unrealized receivables" or appreciated "inventory items" that we own. The term "unrealized receivables" includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and appreciated inventory items may exceed net taxable gain realized on the sale of a common unit and may be recognized even if there is a net taxable loss realized on the sale of a common unit. Thus, a common unitholder may recognize both ordinary income and a capital loss upon a sale of common units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may be used to offset only capital gains in the case of corporations.
The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an "equitable apportionment" method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner's tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner's entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling common unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low tax basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of common units transferred. A common unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A common unitholder considering the purchase of additional common units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury Regulations.
Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an "appreciated"
163
partnership interest, that is, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:
- •
- a short sale;
- •
- an offsetting notional principal contract; or
- •
- a futures or forward contract with respect to the partnership interest or substantially identical property.
Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.
Allocations Between Transferors and Transferees
In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of common units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the "Allocation Date"). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a common unitholder transferring common units may be allocated income, gain, loss and deduction realized after the date of transfer.
Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or applies to only transfers of less than all of the common unitholder's interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among transferor and transferee unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
A common unitholder who owns common units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.
Notification Requirements
A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker who will satisfy such requirements.
164
Constructive Termination
We will be considered to have terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a common unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.
Uniformity of Common Units
Because we cannot match transferors and transferees of common units, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these common units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the common units. Please read "—Tax Consequences of Common Unit Ownership—Section 754 Election."
We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of the property's unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read "—Tax Consequences of Common Unit Ownership—Section 754 Election." To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring common units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If we adopt this position, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. We will not adopt this position if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any common units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of common units might be affected, and the
165
gain from the sale of common units might be increased without the benefit of additional deductions. Please read "—Disposition of Common Units—Recognition of Gain or Loss."
Tax-Exempt Organizations and Other Investors
Ownership of common units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.
Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a common unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.
A regulated investment company, or "mutual fund," is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of common units in a "qualified publicly traded partnership" is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly traded partnership.
Non-resident aliens and foreign corporations, trusts or estates that own common units will be considered to be engaged in business in the United States because of the ownership of common units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to non-U.S. unitholders. Each non-U.S. common unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.
In addition, because a foreign corporation that owns common units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation's "U.S. net equity," that is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate common unitholder is a "qualified resident." In addition, this type of common unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.
A non-U.S. common unitholder who sells or otherwise disposes of a common unit will be subject to federal income tax on gain realized on the sale or disposition of that common unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. common unitholder. Under a ruling published by the IRS interpreting the scope of "effectively connected income," a non-U.S. unitholder would be considered to be engaged in a trade or business in the United States by virtue of the U.S. activities of the partnership, and part or all of that unitholder's gain would be effectively connected with that unitholder's indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder of a publicly traded partnership would be subject to U.S. federal income tax or withholding tax upon the sale or disposition of a unit to the extent of the unitholder's share of the partnership's U.S. real property holdings if he owns 5% or more of the units at any point during the five-year period ending on the date of such disposition. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.
166
Administrative Matters
Information Returns and Audit Procedures
We intend to furnish to each common unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each common unitholder's share of income, gain, loss and deduction.
We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the common units.
The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each common unitholder to adjust a prior year's tax liability and possibly may result in an audit of his own return. Any audit of a common unitholder's return could result in adjustments not related to our returns as well as those related to our returns.
Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the "Tax Matters Partner" for these purposes. The partnership agreement appoints the General Partner as our Tax Matters Partner.
The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a common unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that common unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any common unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each common unitholder with an interest in the outcome may participate.
A common unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a common unitholder to substantial penalties.
Nominee Reporting
Persons who hold an interest in us as a nominee for another person are required to furnish to us:
- (a)
- the name, address and taxpayer identification number of the beneficial owner and the nominee;
- (b)
- a statement regarding whether the beneficial owner is:
- (1)
- a person that is not a U.S. person,
- (2)
- a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or
167
- (c)
- the amount and description of common units held, acquired or transferred for the beneficial owner; and
- (d)
- specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.
Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on common units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the common units with the information furnished to us.
Accuracy-Related Penalties
An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.
For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:
- (1)
- for which there is, or was, "substantial authority," or
- (2)
- as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.
If any item of income, gain, loss or deduction included in the distributive shares of unitholders could result in that kind of an "understatement" of income for which no "substantial authority" exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to "tax shelters," which we do not believe includes us.
A substantial valuation misstatement exists if the value of any property, or the adjusted tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted tax basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 200% or more than the correct valuation, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.
Reportable Transactions
If we were to engage in a "reportable transaction," we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a "listed transaction" or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2.0 million in any single year, or $4.0 million in any combination of six successive tax years. Our participation in a reportable
168
transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read "—Information Returns and Audit Procedures" above.
Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:
- •
- accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at "—Accuracy-Related Penalties,"
- •
- for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and
- •
- in the case of a listed transaction, an extended statute of limitations.
We do not expect to engage in any reportable transactions.
State, Local and Other Tax Considerations
In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which you are a resident. We will initially conduct business and own property in Texas and California. California imposes a personal income tax on individuals and Texas and California impose an entity level tax on corporations and other entities. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective common unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholder's income tax liability to the state, generally does not relieve a nonresident common unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read "—Tax Consequences of Common Unit Ownership—Entity-Level Collections." Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.
It is the responsibility of each common unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective common unitholder consult, and depend on, his own tax counsel or other advisor with regard to those matters. It is the responsibility of each common unitholder to file all tax returns, that may be required of him.
169
INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS
An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, "Similar Laws"). For these purposes the term "employee benefit plan" includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities ("IRAs") established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include "plan assets" of such plans, accounts and arrangements. Among other things, consideration should be given to:
- •
- whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;
- •
- whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;
- •
- whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws; and
- •
- whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read "Material Tax Consequences—Tax-Exempt Organizations and Other Investors."
The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.
Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving "plan assets" with parties that are "parties in interest" under ERISA or "disqualified persons" under the Internal Revenue Code with respect to the plan unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the employee benefit plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.
In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code and any other applicable Similar Laws.
The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed "plan assets" under some circumstances. Under these regulations, an entity's assets would not be considered to be "plan assets" if, among other things:
- (a)
- the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under certain provisions of the federal securities laws;
170
- (b)
- the entity is an "operating company,"—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or
- (c)
- there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above that are subject to ERISA, IRAs and similar vehicles that are subject to Section 4975 of the Internal Revenue Code.
Our assets should not be considered "plan assets" under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirement in (c) above.
Plan fiduciaries contemplating a purchase of our common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.
171
UNDERWRITING
Lehman Brothers Inc., Citigroup Global Markets Inc., and UBS Securities LLC are acting as representatives of the underwriters and as joint book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to this registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:
Underwriters
| | Number of Common Units
|
---|
Lehman Brothers Inc. | | |
Citigroup Global Markets Inc. | | |
UBS Securities LLC | | |
| |
|
| Total | | 9,100,000 |
| |
|
The underwriting agreement provides that the underwriters' obligation to purchase the common units depends on the satisfaction of the conditions contained in the underwriting agreement including:
- •
- the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional common units as described below) if any of the common units are purchased;
- •
- the representations and warranties made by us to the underwriters are true;
- •
- there has been no material change in our business or in the financial markets; and
- •
- we deliver customary closing documents to the underwriters.
Commissions and Expenses
The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters' option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.
| | No Exercise
| | Full Exercise
|
---|
Per Unit | | $ | | | $ | |
Total | | $ | | | $ | |
The representatives have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $ per unit. After the offering, the representatives may change the offering price and other selling terms.
The expenses of the offering that are payable by us are estimated to be $2.0 million (excluding underwriting discounts and commissions and the structuring fee described below).
We will pay a structuring fee equal to $ (or $ if the underwriters exercise their option to purchase additional common units in full) to Lehman Brothers Inc. for evaluation, analysis and structuring of our partnership and its initial public offering.
172
Option to Purchase Additional Common Units
We have granted the underwriters an option exercisable for 30 days after the date of the underwriting agreement to purchase, from time to time, in whole or in part, up to an aggregate of 1,365,000 common units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than 9,100,000 common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter's percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.
Lock-Up Agreements
We, our subsidiaries, our general partner and certain of its affiliates, including the directors and executive officers of our general partner, the participants in our directed unit program and Venoco have agreed that, without the prior written consent of the representatives, we and they will not directly or indirectly, (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any common units (including, without limitation, common units that may be deemed to be beneficially owned by the undersigned in accordance with the rules and regulations of the Securities and Exchange Commission and common units that may be issued upon exercise of any option or warrant) or securities convertible into or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of common units, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common units or other securities, in cash or otherwise, (3) cause to be filed a registration statement with respect to any common units or securities convertible, exercisable or exchangeable into common units or any other securities of the Company or (4) publicly disclose the intention to do any of the foregoing, for a period of 180 days after the date of the final prospectus relating to the Offering.
The 180-day restricted period described in the preceding paragraph will be extended if:
- •
- during the last 17 days of the 180-day restricted periods we issue an earnings release or announce material news or a material event; or
- •
- prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day period,
in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.
The restrictions described in this paragraph do not apply to:
- •
- the issuance and sale of common units by us to the underwriters pursuant to the underwriting agreement; or
- •
- the issuance and sale of common units, phantom units, restricted units and options under our existing employee benefits plans, including sales pursuant to "cashless-broker" exercises of options to purchase common units in accordance with such plans as consideration for the exercise price and withholding taxes applicable to such exercises.
The representatives, in their sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time with or without notice. When determining whether or not to release common units and other securities from lock-up agreements, the representatives will consider, among other factors, the holder's reasons for requesting
173
the release, the number of common units and other securities for which the release is being requested and market conditions at the time.
As described below under "—Directed Unit Program," any participants in the Directed Unit Program shall be subject to a 180-day lock-up with respect to any common units sold to them pursuant to that program. This lock-up will have similar restrictions and an identical extension provision as the lock-up agreement described above. Any common units sold in the Directed Unit Program to our general partner's directors or officers will be subject to the lock-up agreement described above.
Offering Price Determination
Prior to this offering, there has been no public market for our common units. The initial public offering price was negotiated between the representatives and us. In determining the initial public offering price of our common units, the representative considered:
- •
- the history and prospects for the industry in which we compete;
- •
- our financial information;
- •
- the ability of our management and our business potential and earnings prospects;
- •
- the prevailing securities markets at the time of this offering; and
- •
- the recent market prices of, and the demand for, publicly traded common units of generally comparable master limited partnerships.
Indemnification
We, our subsidiaries and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933 and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities.
Directed Unit Program
At our request, Lehman Brothers Inc. has established a Directed Unit Program under which they have reserved up to common units offered hereby at the public offering price for officers, directors, employees and certain other persons associated with us. The number of common units available for sale to the general public will be reduced to the extent such persons purchase common units reserved under the Directed Unit Program. Any reserved common units not so purchased will be offered by the underwriters to the general public on the same basis as the other common units offered hereby. Any participants in this program shall be prohibited from selling, pledging or assigning any units sold to them pursuant to this program for a period of 180 days after the date of this prospectus. This 180-day period shall be extended with respect to our issuance of an earnings release or if material news or a material event relating to us occurs, in the same manner as described above under "—Lock-Up Agreements."
Stabilization, Short Positions and Penalty Bids
The underwriters may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Securities Exchange Act of 1934:
- •
- Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
174
- •
- A short position involves a sale by the underwriters of common units in excess of the number of units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of common units involved in the sales made by the underwriters in excess of the number of units they are obligated to purchase is not greater than the number of units that they may purchase by exercising their option to purchase additional common units. In a naked short position, the number of units involved is greater than the number of units in their option to purchase additional common units. The underwriters may close out any short position by either exercising their option to purchase additional common units and/or purchasing common units in the open market. In determining the source of common units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option to purchase additional common units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.
- •
- Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.
- •
- Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.
Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.
Electronic Distribution
A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.
Other than the prospectus in electronic format, the information on any underwriter's or selling group member's web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.
175
New York Stock Exchange
We intend to apply to list our common units for quotation on the New York Stock Exchange under the symbol "VAC." In connection with that listing, the underwriters have undertaken to sell the common units in this offering to the minimum number of beneficial owners minimum number necessary meet the New York Stock Exchange listing requirements.
Discretionary Sales
The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of shares offered by them.
Stamp Taxes
If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.
Relationships/NASD Conduct Rules
We and our subsidiaries may from time to time enter into other investment banking relationships with the underwriters or their affiliates pursuant to which the underwriters will receive customary fees and will be entitled to reimbursement for all related reasonable disbursements and out-of-pocket expenses. We expect that any arrangement will include provisions for the indemnification of the underwriters against a variety of liabilities, including liabilities under the federal securities laws. Certain affiliates of Lehman Brothers Inc., Citigroup Global Markets Inc. and UBS Securities LLC serve as agents, arrangers and lenders under Venoco's revolving credit agreement and Venoco's term loan agreement for which they have received customary compensation in such capacities. Accordingly, each will receive a portion of the proceeds from this offering through Venoco's partial repayment of its indebtedness under these credit facilities. Pursuant to these credit facilities, Venoco has also agreed to indemnify such persons against a variety of liabilities and to reimburse certain expenses.
Because the Financial Industry Regulatory Authority, or FINRA, views the common units offered by this prospectus as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD Conduct Rules (which are part of the FINRA Rules). Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange. Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us. They have received customary fees and commissions for these transactions.
176
VALIDITY OF THE COMMON UNITS
The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Akin Gump Strauss Hauer & Feld LLP.
EXPERTS
The financial statements of Venoco Acquisition Company, L.P. Predecessor as of December 31, 2006 and 2005 and for each of the three years in the period ended December 31, 2006 included in this prospectus have been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.
The balance sheet of Venoco Acquisition Company GP LLC as of February 8, 2008 included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and has been included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.
The balance sheet of Venoco Acquisition Company, L.P. as of February 8, 2008 included in this prospectus has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein, and has been included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.
The statements of revenues and direct operating expenses for the Hastings Complex for the year ended December 31, 2005 and the three months ended March 31, 2006 included in this prospectus have been so included in reliance on the report of BDO Seidman LLP, an independent registered public accounting firm, appearing elsewhere herein, given on their authority as experts in accounting and auditing.
The statements of revenues and direct operating expenses for the West Montalvo Onshore Operations for each of the two years in the period ended December 31, 2006 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
177
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the Securities and Exchange Commission, or the SEC, a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC's web site.
We intend to furnish our unitholders annual reports containing our audited financial statements and furnish or make available quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.
178
FORWARD-LOOKING STATEMENTS
Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including "may," "believe," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition, or state other "forward-looking" information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement:
- •
- prices we receive for our oil and natural gas production;
- •
- our ability to replace the reserves we produce through drilling and property acquisitions;
- •
- our ability to attract the capital; and
- •
- the other matters discussed under "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations," "Business" and elsewhere in this prospectus.
179
INDEX TO FINANCIAL STATEMENTS
VENOCO ACQUISITION COMPANY, L.P. | | |
Introduction | | F-2 |
Unaudited Pro Forma Balance Sheet as of September 30, 2007 | | F-3 |
Unaudited Pro Forma Statement of Operations for the year ended December 31, 2006 | | F-4 |
Unaudited Pro Forma Statement of Operations for the nine months ended September 30, 2007 | | F-5 |
Notes to Unaudited Pro Forma Financial Statements | | F-6 |
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR | | |
Report of Independent Registered Public Accounting Firm | | F-11 |
Audited Carve-Out Balance Sheets as of December 31, 2005 and 2006 | | F-12 |
Audited Carve-Out Statements of Operations for the years ended December 31, 2004, 2005 and 2006 | | F-13 |
Audited Carve-Out Statements of Changes In Owner's Net Equity for the years ended December 31, 2004, 2005 and 2006 | | F-14 |
Audited Carve-Out Statements of Cash Flows for the years ended December 31, 2004, 2005 and 2006 | | F-15 |
Notes to Audited Carve-Out Financial Statements | | F-16 |
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR | | |
Unaudited Carve-Out Balance Sheets as of December 31, 2006 and September 30, 2007 | | F-29 |
Unaudited Carve-Out Statements of Operations for the nine months ended September 30, 2006 and 2007 | | F-30 |
Unaudited Carve-Out Statements of Cash Flows for the nine months ended September 30, 2006 and 2007 | | F-31 |
Notes to Unaudited Carve-Out Financial Statements | | F-32 |
VENOCO ACQUISITION COMPANY, L.P. | | |
Report of Independent Registered Public Accounting Firm | | F-37 |
Audited Balance Sheet as of February 8, 2008 | | F-38 |
Notes to Audited Balance Sheet | | F-39 |
VENOCO ACQUISITION COMPANY GP, LLC | | |
Report of Independent Registered Public Accounting Firm | | F-40 |
Audited Balance Sheet as of February 8, 2008 | | F-41 |
Notes to Audited Balance Sheet | | F-42 |
HASTINGS COMPLEX | | |
Report of Independent Registered Public Accounting Firm | | F-43 |
Audited Statements of Revenues and Direct Operating Expenses for the year ended December 31, 2005 and the three months ended March 31, 2006 | | F-44 |
Notes to Audited Statements of Revenues and Direct Operating Expenses | | F-45 |
WEST MONTALVO ONSHORE OPERATIONS | | |
Report of Independent Registered Public Accounting Firm | | F-49 |
Audited Statements of Revenues and Direct Operating Expenses for the years ended December 31, 2005 and 2006 | | F-50 |
Notes to Audited Statements of Revenues and Direct Operating Expenses | | F-51 |
WEST MONTALVO ONSHORE OPERATIONS | | |
Unaudited Statements of Revenues and Direct Operating Expenses for the three months ended March 31, 2006 and 2007 | | F-55 |
Notes to Unaudited Statements of Revenues and Direct Operating Expenses | | F-56 |
F-1
VENOCO ACQUISITION COMPANY, L.P.
UNAUDITED PRO FORMA FINANCIAL STATEMENTS
INTRODUCTION
Venoco Acquisition Company, L.P. (the "Partnership") was formed in September 2007 as a Delaware limited partnership to acquire, produce, exploit, and develop oil and natural gas properties. Currently, Venoco, Inc., a publicly traded Delaware corporation ("Venoco"), owns all general and limited partner interests in the Partnership. The Partnership plans to pursue an initial public offering (the "Offering") of common units representing limited partner interests. Effective at the closing of the Offering, Venoco will exchange certain oil and natural gas properties and related assets located in California and onshore Texas (the "Partnership Properties") for additional limited partner interests in the Partnership.
The unaudited pro forma financial statements of the Partnership for the year ended December 31, 2006 and as of and for the nine months ended September 30, 2007, are derived from the historical audited and unaudited carve-out financial statements of Venoco Acquisition Company, L.P. Predecessor (the "Predecessor"), respectively.
The contribution of the Partnership Properties by Venoco to the Partnership will be recorded at historical cost as it is considered to be a reorganization of entities under common control. Unless the context otherwise requires, references herein to the Partnership include the Partnership and its operating companies. The pro forma adjustments have been prepared assuming that the Offering occurred on September 30, 2007, in the case of the pro forma balance sheet, and assuming that the Offering and the acquisitions of certain of the Partnership Properties occurred on January 1, 2006, in the case of the pro forma statements of operations. The unaudited pro forma financial statements have been prepared on the assumption that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma financial statements should be read in conjunction with the notes accompanying such unaudited pro forma financial statements and with the historical carve-out financial statements and related notes set forth elsewhere in this Prospectus.
The unaudited pro forma balance sheet and the unaudited pro forma statements of operations were derived by adjusting the historical carve-out financial statements of the Predecessor. The adjustments are based on currently available information and certain estimates and assumptions. Actual effects of these transactions will differ from the pro forma adjustments. However, the Predecessor's management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to the expected impact of events that are directly attributable to the formation of the Partnership, the transfer of the operations of the Predecessor and the related transactions, and that are expected to have a continuing impact on the Partnership.
The unaudited pro forma financial statements are not necessarily indicative of the results that actually would have occurred if the Partnership had assumed the operations of the Predecessor on the dates indicated or which will be obtained in the future.
F-2
VENOCO ACQUISITION COMPANY, L.P.
UNAUDITED PRO FORMA BALANCE SHEET
AS OF SEPTEMBER 30, 2007
(In thousands)
| | Historical Predecessor
| | Pro Forma Offering Adjustments
| | Pro Forma As Adjusted
| |
---|
ASSETS | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | |
| Cash and cash equivalents | | $ | — | | $
| 167,488 117,488 39,200 (45,000 (156,688 (117,488 | (b) (c) (d) )(e) )(f) )(g) | $ | 5,000 | |
| Accrued accounts receivable | | | 11,289 | | | | | | 11,289 | |
| |
| |
| |
| |
| | Total current assets | | | 11,289 | | | 5,000 | | | 16,289 | |
| |
| |
| |
| |
PROPERTY, PLANT AND EQUIPMENT, AT COST: | | | | | | | | | | |
| Oil and natural gas properties, full cost method | | | 180,843 | | | | | | 180,843 | |
| Accumulated depletion, depreciation and amortization | | | (34,943 | ) | | | | | (34,943 | ) |
| |
| | | | |
| |
| | Net property, plant and equipment | | | 145,900 | | | | | | 145,900 | |
| |
| | | | |
| |
MARKETABLE SECURITIES | | | — | | | 117,488 | (g) | | 117,488 | |
OTHER ASSETS | | | 3,599 | | | 800 (1,088 | (d) )(a) | | 3,311 | |
| |
| |
| |
| |
TOTAL ASSETS | | $ | 160,788 | | $ | 122,200 | | $ | 282,988 | |
| |
| |
| |
| |
LIABILITIES AND PARTNERS' EQUITY | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | |
| Accrued liabilities | | $ | 16,369 | | $ | | | $ | 16,369 | |
| Current taxes payable | | | 42 | | | | | | 42 | |
| Current asset retirement obligations | | | 496 | | | | | | 496 | |
| |
| |
| |
| |
| | Total current liabilities | | | 16,907 | | | | | | 16,907 | |
| |
| |
| |
| |
LONG-TERM DEBT | | | 83,141 | | | (83,141 117,488 40,000 | )(a) (c) (d) | | 157,488 | |
DEFERRED INCOME TAXES | | | 62 | | | | | | 62 | |
ASSET RETIREMENT OBLIGATIONS | | | 12,883 | | | | | | 12,883 | |
| |
| |
| |
| |
| Total liabilities | | | 112,993 | | | 74,347 | | | 187,340 | |
| |
| |
| |
| |
PARTNERS' EQUITY | | | | | | | | | | |
Owner's net equity | | | 47,795 | | | 82,053 (45,000 (156,688 71,840 | (a) )(e) )(f) (h) | | — | |
Common unitholders—public | | | — | | | 167,488 | (b) | | 167,488 | |
Common unitholders—sponsor | | | — | | | (38,043 | )(h) | | (38,043 | ) |
Subordinated unitholders—sponsor | | | — | | | (31,294 | )(h) | | (31,294 | ) |
General partner interest | | | | | | (2,503 | )(h) | | (2,503 | ) |
| |
| |
| |
| |
Total partners' equity | | | 47,795 | | | 47,853 | | | 95,648 | |
| |
| |
| |
| |
TOTAL LIABILITIES AND PARTNERS' EQUITY | | $ | 160,788 | | $ | 122,200 | | $ | 282,988 | |
| |
| |
| |
| |
See Notes to Unaudited Pro Forma Financial Statements.
F-3
VENOCO ACQUISITION COMPANY, L.P.
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2006
(In thousands, except per unit amounts)
| | Historical Predecessor
| | Pro Forma Acquisitions Adjustments
| | Pro Forma Offering Adjustments
| | Pro Forma As Adjusted
| |
---|
REVENUES: | | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 58,587 | | $ | 14,375 | (i) | $ | | | $ | 72,962 | |
| Pipeline fees | | | 7,595 | | | | | | | | | 7,595 | |
| |
| |
| |
| |
| |
| | Total revenues | | | 66,182 | | | 14,375 | | | | | | 80,557 | |
| |
| |
| |
| |
| |
EXPENSES: | | | | | | | | | | | | | |
| Lease operating expense | | | 24,031 | | | 5,616 | (i) | | | | | 29,647 | |
| Production and property taxes | | | 1,473 | | | 209 | (i) | | | | | 1,682 | |
| Transportation expense | | | 970 | | | | | | | | | 970 | |
| Pipeline operating expense | | | 2,341 | | | | | | | | | 2,341 | |
| Depletion, depreciation and amortization | | | 5,542 | | | 2,011 | (j) | | | | | 7,553 | |
| Accretion of asset retirement obligations | | | 716 | | | 127 | (k) | | | | | 843 | |
| General and administrative expense | | | 4,048 | | | | | | | | | 4,048 | |
| |
| |
| |
| |
| |
| | Total expenses | | | 39,121 | | | 7,963 | | | | | | 47,084 | |
| |
| |
| |
| |
| |
Income from operations | | | 27,061 | | | 6,412 | | | | | | 33,473 | |
FINANCING COSTS AND OTHER: | | | | | | | | | | | | | |
| Interest income | | | — | | | | | | (5,369 | )(l) | | (5,369 | ) |
| Interest expense | | | 4,997 | | | | | | 9,022 (4,997 | (l) )(a) | | 9,022 | |
| Amortization of deferred loan costs | | | 651 | | | | | | (651 200 | )(a) (m) | | 200 | |
| |
| |
| |
| |
| |
| | Total financing costs and other | | | 5,648 | | | | | | (1,795 | ) | | 3,853 | |
| |
| |
| |
| |
| |
Income before income taxes | | | 21,413 | | | 6,412 | | | 1,795 | | | 29,620 | |
Income taxes | | | 14 | | | | | | | | | 14 | |
| |
| |
| |
| |
| |
Net income | | $ | 21,399 | | $ | 6,412 | | $ | 1,795 | | $ | 29,606 | |
| |
| |
| |
| |
| |
General partner's interest in net income | | | | | | | | | | | $ | 592 | |
| | | | | | | | | | |
| |
Limited partners' interest in net income | | | | | | | | | | | $ | 29,014 | |
| | | | | | | | | | |
| |
Net income per limited partner unit: | | | | | | | | | | | | | |
| Common units | | | | | | | | | | | $ | 1.75 | |
| | | | | | | | | | |
| |
| Subordinated units | | | | | | | | | | | $ | 0.32 | |
| | | | | | | | | | |
| |
Weighted average number of limited partner units outstanding: | | | | | | | | | | | | | |
| Common units | | | | | | | | | | | | 15,591 | |
| | | | | | | | | | |
| |
| Subordinated units | | | | | | | | | | | | 5,339 | |
| | | | | | | | | | |
| |
See Notes to Unaudited Pro Forma Financial Statements.
F-4
VENOCO ACQUISITION COMPANY, L.P.
UNAUDITED PRO FORMA STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2007
(In thousands, except per unit amounts)
| | Historical Predecessor
| | Pro Forma Acquisitions Adjustments
| | Pro Forma Offering Adjustments
| | Pro Forma As Adjusted
| |
---|
REVENUES: | | | | | | | | | | | | | |
| Oil and natural gas sales | | $ | 56,056 | | $ | 2,978 | (i) | $ | | | $ | 59,034 | |
| Pipeline fees | | | 5,695 | | | | | | | | | 5,695 | |
| |
| |
| |
| |
| |
| | Total revenues | | | 61,751 | | | 2,978 | | | | | | 64,729 | |
| |
| |
| |
| |
| |
EXPENSES: | | | | | | | | | | | | | |
| Lease operating expense | | | 22,617 | | | 1,237 | (i) | | | | | 23,854 | |
| Production and property taxes | | | 1,249 | | | | | | | | | 1,249 | |
| Transportation expense | | | 684 | | | | | | | | | 684 | |
| Pipeline operating expense | | | 1,536 | | | | | | | | | 1,536 | |
| Depletion, depreciation and amortization | | | 7,447 | | | 500 | (j) | | | | | 7,947 | |
| Accretion of asset retirement obligations | | | 682 | | | 32 | (k) | | | | | 714 | |
| General and administrative expense | | | 3,696 | | | | | | | | | 3,696 | |
| |
| |
| |
| |
| |
| | Total expenses | | | 37,911 | | | 1,769 | | | | | | 39,680 | |
| |
| |
| |
| |
| |
Income from operations | | | 23,840 | | | 1,209 | | | | | | 25,049 | |
FINANCING COSTS AND OTHER: | | | | | | | | | | | | | |
| Interest income | | | — | | | | | | (4,027 | )(l) | | (4,027 | ) |
| Interest expense | | | 5,139 | | | | | | 6,767 (5,139 | (l) )(a) | | 6,767 | |
| Amortization of deferred loan costs | | | 412 | | | | | | (412 150 | )(a) (m) | | 150 | |
| Loss on extinguishment of debt | | | 1,061 | | | | | | (1,061 | )(a) | | — | |
| |
| |
| |
| |
| |
| | Total financing costs and other | | | 6,612 | | | | | | (3,722 | ) | | 2,890 | |
| |
| |
| |
| |
| |
Income before income taxes | | | 17,228 | | | 1,209 | | | 3,722 | | | 22,159 | |
Income taxes | | | 91 | | | | | | | | | 91 | |
| |
| |
| |
| |
| |
Net income | | $ | 17,137 | | $ | 1,209 | | $ | 3,722 | | $ | 22,068 | |
| |
| |
| |
| |
| |
General partner's interest in net income | | | | | | | | | | | $ | 441 | |
| | | | | | | | | | |
| |
Limited partners' interest in net income | | | | | | | | | | | $ | 21,627 | |
| | | | | | | | | | |
| |
Net income per limited partner unit: | | | | | | | | | | | | | |
| Common units | | | | | | | | | | | $ | 1.31 | |
| | | | | | | | | | |
| |
| Subordinated units | | | | | | | | | | | $ | 0.22 | |
| | | | | | | | | | |
| |
Weighted average number of limited partner units outstanding: | | | | | | | | | | | | | |
| Common units | | | | | | | | | | | | 15,591 | |
| | | | | | | | | | |
| |
| Subordinated units | | | | | | | | | | | | 5,339 | |
| | | | | | | | | | |
| |
See Notes to Unaudited Pro Forma Financial Statements.
F-5
VENOCO ACQUISITION COMPANY, L.P.
NOTES TO UNAUDITED PRO FORMA FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION, THE OFFERING AND OTHER TRANSACTIONS
The unaudited pro forma financial statements of Venoco Acquisition Company, L.P. (the "Partnership") have been prepared from information derived from historical audited and unaudited carve-out financial statements of Venoco Acquisition Company, L.P. Predecessor appearing elsewhere in this Prospectus, and the assumptions outlined in Note 2 below. The unaudited pro forma statements of operations assumes the Offering and related transactions as described in this Prospectus and the acquisition of certain of the Partnership Properties occurred on January 1, 2006. The unaudited pro forma balance sheet assumes that the Offering and related transactions occurred as of September 30, 2007. These adjustments do not include the effects of the exercise of the underwriters' over-allotment option. The adjustments are based upon currently available information and certain estimates and assumptions, and therefore the actual effects of these transactions will differ from the pro forma adjustments.
The unaudited pro forma financial statements reflect the following significant assumptions and transactions:
- •
- the acquisitions of the Hastings Complex and the onshore portion of the West Montalvo field as if these acquisitions occurred on January 1, 2006;
- •
- the contribution of the Partnership Properties to the Partnership by Venoco;
- •
- a cash distribution of approximately $45.0 million to Venoco as reimbursement of certain capital expenditures incurred by Venoco prior to the Offering;
- •
- the issuance of 6,490,714 common units, 5,339,286 subordinated units, the 2% general partner interest and the incentive distribution rights to Venoco;
- •
- the Partnership's sale of 9,100,000 common units to the public and the application of the net proceeds of approximately $167.5 million as described in "Use of Proceeds;" and
- •
- the Partnership's borrowing of approximately $157.5 million ($117.5 million of which will be secured by marketable securities which the Partnership intends to purchase with a portion of the net proceeds of this offering) under the Partnership's new credit facility, the net proceeds of which will be distributed to Venoco.
At the closing of the Offering, we expect to incur additional general and administrative expense as a result of being a publicly traded partnership, including incremental costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-l preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, director and officer liability insurance costs, and independent director compensation. We estimate this additional general and administrative expense initially to total approximately $1.0 million per year. This additional general and administrative expense is not reflected in our historical or pro forma financial statements.
2. PRO FORMA ADJUSTMENTS AND ASSUMPTIONS
- a)
- Reflects the elimination of historical debt, deferred loan costs, interest expense and amortization of deferred loan costs in connection with the closing of the Offering as the historical debt balances will not be assumed by the Partnership.
- b)
- Reflects estimated proceeds to the Partnership of approximately $167.5 million from the issuance and sale of 9,100,000 common units at an assumed initial public offering price of
F-6
Common units accrue cumulative cash distributions for any period in which the available cash is not adequate to achieve the minimum distribution of $0.4375 per quarter.
The subordinated units may convert to common units should certain performance milestones be reached. The subordination period also will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis, and the common units will no longer be entitled to arrearages.
The above assumes that the underwriters' over-allotment option is not exercised. If the underwriters exercise their option to purchase additional common units in full, we will use the additional $25.4 million of net proceeds to purchase marketable securities, which will be assigned as collateral to secure an equivalent amount of additional borrowings under our new credit facility.
- i)
- Reflects additional revenues and direct operating expenses related to the Hastings Complex (which was acquired on March 31, 2006) and the onshore portion of the West Montalvo field (which was acquired on May 11, 2007).
- j)
- Reflects additional depletion, depreciation, and amortization resulting from an increase in oil and natural gas properties in connection with the acquisitions of the Hastings Complex and the onshore portion of the West Montalvo field.
F-7
- k)
- Reflects additional accretion of asset retirement obligations resulting from an increase in asset retirement obligations in connection with the acquisitions of the Hastings Complex and the onshore portion of the West Montalvo field.
- l)
- Reflects the interest expense related to the borrowings described in (c) and (d) above, and the interest income related to the securities described in (g) above. The interest expense for the borrowings described in (c) above is based on an estimated average variable rate of 4.87%. The interest expense for the borrowings described in (d) above is based on an estimated average variable interest rate of 8.25%. The interest income is based on an estimated average variable rate of 4.57%. A change of 1% would have increased or decreased pro forma net interest expense by $0.4 million for 2006 and $0.3 million for the nine months ended September 30, 2007.
- m)
- Reflects the amortization of the deferred debt issuance costs related to the debt described in (c) and (d) above over the 4 year term of the associated debt.
3. PRO FORMA NET INCOME PER UNIT
Pro forma net income per limited partner unit is determined by dividing the pro forma net income, that would have been allocated in accordance with the net income and loss allocation provisions of the limited partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting the general partner's 2% interest in pro forma net income, by the number of common and subordinated units expected to be outstanding at the closing of the Offering. For purposes of this calculation, we assumed the number of units outstanding were 15,590,714 common units and 5,339,286 subordinated units. All units were assumed to have been outstanding since January 1, 2006. Basic and diluted pro forma net income per unit are equivalent as there will be no dilutive units at the date of the closing of the Offering of the common units of the Partnership. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.
Emerging Issues Task Force Issue No. 03-06, Participating Securities and the Two-Class Method under FASB Statement No. 128, addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity. EITF 03-06 provides that the general partner's interest in net income is to be calculated based on the amount that would be allocated to the general partner if all the net income for the period were distributed, and not on the basis of actual cash distributions for the period. The application of EITF 03-06 may have an impact on earnings per limited partner unit in future periods if there are material differences between net income and actual cash distributions or if other participating securities are issued.
Staff Accounting Bulletin 1:B:3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. Upon completion of this Offering, we intend to distribute approximately $201.7 million in cash to Venoco. This distribution will be paid with (i) $156.7 million of borrowings under the new revolving credit
F-8
facility, and (ii) $45.0 million from the proceeds of the issuance and sale of common units. Assuming additional common units were issued to give effect to this distribution, pro forma net income per common unit would have been $1.61 and $1.20 for the year ended December 31, 2006 and the nine-months ended September 30, 2007, respectively, and pro forma net income per subordinated unit would have been $0.00 for the year ended December 31, 2006 and the nine-months ended September 30, 2007.
4. PRO FORMA OIL & NATURAL GAS PRODUCING ACTIVITIES
The following table sets forth pro forma net proved reserves, including changes, and proved developed reserves (all within the United States) as of and for the year ended December 31, 2006.
| | Crude Oil, Liquids and Condensate (MBbl)
| | Natural Gas (MMcf)
| |
---|
Beginning of the year reserves | | 18,475 | | 18,513 | |
Revisions of previous estimates | | 934 | | 92 | |
Extensions, discoveries and improved recovery | | — | | — | |
Production | | (1,140 | ) | (1,122 | ) |
| |
| |
| |
End of year reserves | | 18,269 | | 17,483 | |
| |
| |
| |
Proved developed reserves: | | | | | |
| Beginning of year | | 8,831 | | 13,598 | |
| End of year | | 14,886 | | 13,731 | |
Pro Forma Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The pro forma standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of December 31, 2006 is as follows.
| | (In thousands)
| |
---|
Future cash inflows | | $ | 1,060,594 | |
Future production costs | | | (523,815 | ) |
Future development costs | | | (53,676 | ) |
Future income taxes | | | (1,547 | ) |
| |
| |
Future net cash flows | | | 481,556 | |
10% annual discount for estimated timing of cash flows | | | (209,215 | ) |
| |
| |
Standardized measure of discounted future net cash flows | | $ | 272,341 | |
| |
| |
F-9
The following table summarizes changes in the pro forma standardized measure of discounted future net cash flows for the year ended December 31, 2006.
| | (In thousands)
| |
---|
Beginning of the year | | $ | 316,006 | |
Changes in prices and production costs | | | (41,946 | ) |
Revisions of previous quantity estimates | | | 14,793 | |
Changes in future development costs | | | (11,009 | ) |
Development costs incurred during the period | | | 12,168 | |
Sales of oil and natural gas, net of production costs | | | (41,086 | ) |
Accretion of discount | | | 26,401 | |
Net changes in income taxes | | | (914 | ) |
Production timing and other | | | (2,072 | ) |
| |
| |
End of year | | $ | 272,341 | |
| |
| |
F-10
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
REPORT OF INDEPENDENT
REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Venoco, Inc.
Denver, Colorado
We have audited the accompanying carve-out balance sheets of Venoco Acquisition Company, L.P. Predecessor (the "Predecessor") as of December 31, 2006 and 2005, and the related carve-out statements of operations, changes in owner's net equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Predecessor's management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Predecessor is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Predecessor's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such carve-out financial statements present fairly, in all material respects, the financial position of Venoco Acquisition Company, L.P. Predecessor as of December 31, 2006 and 2005, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 11, 2008
F-11
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
CARVE-OUT BALANCE SHEETS
(In thousands)
| | December 31,
| |
---|
| | 2005
| | 2006
| |
---|
ASSETS | | | | | | | |
CURRENT ASSETS: | | | | | | | |
| Accrued accounts receivable | | $ | 4,807 | | $ | 10,385 | |
| |
| |
| |
| | Total current assets | | | 4,807 | | | 10,385 | |
| |
| |
| |
PROPERTY, PLANT AND EQUIPMENT, AT COST: | | | | | | | |
| Oil and natural gas properties, full-cost method | | | 59,490 | | | 107,878 | |
| Accumulated depletion, depreciation and amortization | | | (21,954 | ) | | (27,496 | ) |
| |
| |
| |
| | Net property, plant and equipment | | | 37,536 | | | 80,382 | |
| |
| |
| |
OTHER ASSETS | | | 212 | | | 4,296 | |
| |
| |
| |
| | TOTAL ASSETS | | $ | 42,555 | | $ | 95,063 | |
| |
| |
| |
LIABILITIES AND OWNER'S NET EQUITY | | | | | | | |
CURRENT LIABILITIES: | | | | | | | |
| Accrued liabilities | | $ | 3,519 | | $ | 7,366 | |
| Current asset retirement obligations | | | 28 | | | 29 | |
| |
| |
| |
| | Total current liabilities | | | 3,547 | | | 7,395 | |
| |
| |
| |
DEBT | | | 4,174 | | | 49,965 | |
DEFERRED INCOME TAXES | | | — | | | 14 | |
ASSET RETIREMENT OBLIGATIONS | | | 7,841 | | | 11,388 | |
| |
| |
| |
| Total liabilities | | | 15,562 | | | 68,762 | |
| |
| |
| |
COMMITMENTS AND CONTINGENCIES | | | | | | | |
OWNER'S NET EQUITY | | | 26,993 | | | 26,301 | |
| |
| |
| |
| | TOTAL LIABILITIES AND OWNER'S NET EQUITY | | $ | 42,555 | | $ | 95,063 | |
| |
| |
| |
See Notes to Carve-Out Financial Statements.
F-12
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
CARVE-OUT STATEMENTS OF OPERATIONS
(In thousands)
| | Years Ended December 31,
|
---|
| | 2004
| | 2005
| | 2006
|
---|
REVENUES: | | | | | | | | | |
| Oil and natural gas sales | | $ | 27,230 | | $ | 37,879 | | $ | 58,587 |
| Pipeline fees | | | 6,429 | | | 6,235 | | | 7,595 |
| |
| |
| |
|
| | Total revenue | | | 33,659 | | | 44,114 | | | 66,182 |
| |
| |
| |
|
EXPENSES: | | | | | | | | | |
| Lease operating expense | | | 12,360 | | | 14,339 | | | 24,031 |
| Production and property taxes | | | 263 | | | 365 | | | 1,473 |
| Transportation expense | | | 567 | | | 707 | | | 970 |
| Pipeline operating expense | | | 1,441 | | | 1,617 | | | 2,341 |
| Depletion, depreciation and amortization | | | 2,299 | | | 2,771 | | | 5,542 |
| Accretion of asset retirement obligations | | | 514 | | | 627 | | | 716 |
| General and administrative expense | | | 1,324 | | | 1,984 | | | 4,048 |
| |
| |
| |
|
| | Total expenses | | | 18,768 | | | 22,410 | | | 39,121 |
| |
| |
| |
|
| Income from operations | | | 14,891 | | | 21,704 | | | 27,061 |
FINANCING COSTS: | | | | | | | | | |
| Interest expense | | | 424 | | | 106 | | | 4,997 |
| Amortization of deferred loan costs | | | 101 | | | 155 | | | 651 |
| Loss on extinguishment of debt | | | 457 | | | — | | | — |
| |
| |
| |
|
| | Total financing costs | | | 982 | | | 261 | | | 5,648 |
| |
| |
| |
|
Income before income taxes | | | 13,909 | | | 21,443 | | | 21,413 |
| Income tax provision | | | — | | | — | | | 14 |
| |
| |
| |
|
| Net income | | $ | 13,909 | | $ | 21,443 | | $ | 21,399 |
| |
| |
| |
|
See Notes to Carve-Out Financial Statements.
F-13
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
CARVE-OUT STATEMENTS OF CHANGES IN OWNER'S NET EQUITY
(In thousands)
BALANCE AT JANUARY 1, 2004 | | $ | 14,516 | |
| Net income | | | 13,909 | |
| Distribution to owner | | | (1,666 | ) |
| |
| |
BALANCE AT DECEMBER 31, 2004 | | | 26,759 | |
| Net income | | | 21,443 | |
| Distribution to owner | | | (21,209 | ) |
| |
| |
BALANCE AT DECEMBER 31, 2005 | | | 26,993 | |
| Net income | | | 21,399 | |
| Distributions to owner | | | (22,091 | ) |
| |
| |
BALANCE AT DECEMBER 31, 2006 | | $ | 26,301 | |
| |
| |
See Notes to Carve-Out Financial Statements.
F-14
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
CARVE-OUT STATEMENTS OF CASH FLOWS
(In thousands)
| | Years Ended December 31,
| |
---|
| | 2004
| | 2005
| | 2006
| |
---|
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | |
| Net income | | $ | 13,909 | | $ | 21,443 | | $ | 21,399 | |
| Adjustments to reconcile net income to cash provided by operating activities: | | | | | | | | | | |
| | Depletion, depreciation and amortization | | | 2,299 | | | 2,771 | | | 5,542 | |
| | Accretion of asset retirement obligation | | | 514 | | | 627 | | | 716 | |
| | Deferred income taxes | | | — | | | — | | | 14 | |
| | Amortization of deferred loan costs | | | 101 | | | 155 | | | 651 | |
| | Loss on extinguishment of debt | | | 457 | | | — | | | — | |
| Changes in operating assets and liabilities, net: | | | | | | | | | | |
| | Accrued accounts receivable | | | (1,299 | ) | | (1,526 | ) | | (1,829 | ) |
| | Accrued liabilities | | | 919 | | | 566 | | | 516 | |
| |
| |
| |
| |
| | | Net cash provided by operating activities | | | 16,900 | | | 24,036 | | | 27,009 | |
| |
| |
| |
| |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
| Expenditures for oil and natural gas properties | | | (1,062 | ) | | (715 | ) | | (9,474 | ) |
| Acquisitions of oil and natural gas properties | | | (4,625 | ) | | (6,238 | ) | | (57,750 | ) |
| Proceeds from sale of property and equipment | | | — | | | — | | | 18,750 | |
| |
| |
| |
| |
| | | Net cash used in investing activities | | | (5,687 | ) | | (6,953 | ) | | (48,474 | ) |
| |
| |
| |
| |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
| Proceeds from debt | | | — | | | 4,174 | | | 45,791 | |
| Repayments of debt | | | (8,725 | ) | | — | | | — | |
| Deferred loan costs | | | (822 | ) | | (48 | ) | | (2,235 | ) |
| Contributions from (distributions to) parent | | | (1,666 | ) | | (21,209 | ) | | (22,091 | ) |
| |
| |
| |
| |
| | | Net cash provided by (used in) financing activities | | | (11,213 | ) | | (17,083 | ) | | 21,465 | |
| |
| |
| |
| |
| Net change in cash and cash equivalents | | | — | | | — | | | — | |
| Cash and cash equivalents, beginning of year | | | — | | | — | | | — | |
| |
| |
| |
| |
| Cash and cash equivalents, end of year | | $ | — | | $ | — | | $ | — | |
| |
| |
| |
| |
See Notes to Carve-Out Financial Statements.
F-15
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
NOTES TO CARVE-OUT FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2004, 2005, AND 2006
1. ORGANIZATION, BASIS OF PRESENTATION AND NATURE OF OPERATIONS
Venoco Acquisition Company, L.P. (the "Partnership") is a Delaware limited partnership formed on September 25, 2007 by Venoco, Inc. ("Venoco") to acquire interests in certain oil and natural gas producing properties and related assets located in California and onshore Texas (the "Partnership Properties"). Venoco currently owns all the general and limited partner interests in the Partnership. The Partnership intends to pursue an initial public offering of its common units representing limited partner interests (the "Offering"). At the closing of the Offering, Venoco will contribute the Partnership Properties to the Partnership in exchange for cash, common units and subordinated units representing a 55.4% limited partner interest, and a 2% general partner interest (the "Formation Transactions").
The accompanying carve-out financial statements and related notes thereto represent the carve-out financial position, results of operations, cash flows, and changes in owner's net equity of the Partnership Properties. The carve-out financial statements have been prepared in accordance with Regulation S-X, Article 3 "General instructions as to financial statements" and Staff Accounting Bulletin ("SAB") Topic 1-B "Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity" and represent the Partnership's predecessor, referred to herein as Venoco Acquisition Company, L.P. Predecessor (the "Predecessor"). Certain costs and expenses incurred by Venoco are only indirectly attributable to its ownership of the Partnership Properties as Venoco owns interests in other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such costs and expenses to the Predecessor, so that the accompanying carve-out financial statements reflect substantially all the costs of doing business. The allocations and related estimates and assumptions are described more fully in the following Notes. These allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if the Predecessor had been operated as a stand-alone entity.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment tests of long-lived assets; (3) depreciation, depletion and amortization; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with business acquisitions; (6) accrued liabilities; (7) accrued revenue and related receivables and (8) the retroactive allocations and assumptions related to the carve-out process. Although management believes these estimates are reasonable, actual results could differ from these estimates.
Business Segment Information—The Predecessor operates in one segment—the development and exploitation of oil and natural gas reserves. All of those operations are located in the United States and all of the related oil and natural gas revenue are derived from sales to customers located in the United States.
F-16
Concentration of Credit Risk—For purposes of these carve-out financial statements accounts receivable and payable are deemed to be settled monthly with Venoco, through the Owner's net equity account. Accrued accounts receivables result from oil and natural gas sales from the Partnership Properties to major oil and intrastate natural gas pipeline companies. Such receivables are dispersed among various customers and purchasers; therefore, concentrations of credit risk are limited. If customers are considered a credit risk, letters of credit are the primary security obtained to support lines of credit. For the year ended December 31, 2004, oil and natural gas sales to three major customers represented 57%, 24% and 14% of total revenue from the Partnership Properties. For the year ended December 31, 2005, oil and natural gas sales to three major customers represented 56%, 21% and 19% of total revenue from the Partnership Properties. For the year ended December 31, 2006, oil and natural gas sales to three major customers represented 44%, 32% and 12% of total revenue from the Partnership Properties.
Revenue Recognition and Gas Imbalances—Revenues from sales of natural gas and oil are recorded when title to the product has transferred to the customer as defined in related sales contracts. This generally occurs when a barge completes delivery, oil or natural gas has been delivered to a refinery or a pipeline, or has otherwise been transferred to a customer's facilities or possession. Oil revenues are generally recognized based on actual volumes of oil sold. Title to oil sold is typically transferred at the wellhead, except in the case of the South Ellwood field, where title is transferred when the barge that transports production from the field completes delivery.
Natural gas revenues are recognized based on the entitlement method. Under this method, revenues are recognized based on actual production of natural gas and production gas volume imbalances may occur in the ordinary course of business. Net deliveries in excess of entitled amounts are recorded as liabilities, while net under-deliveries are reflected as assets. Imbalances are reduced either by subsequent recoupment of over- and under-deliveries or by cash settlement, as required by applicable contracts. Production imbalances are valued at the lowest of (1) the price in effect at the time of production, (2) the current market value, or (3) if a contract is in-hand, the contract price. Production imbalances were not material at December 31, 2005 and 2006.
Pipeline revenue is composed of fees charged for transportation of oil and natural gas on the Predecessor's pipeline systems. Pipeline revenue for the years ended December 31, 2004, 2005 and 2006 includes $4.3 million, $4.7 million and $4.1 million, respectively, of fees charged by Venoco for transportation of oil and natural gas from the Partnership Properties.
Cash and Cash Equivalents—Venoco provides cash as needed to support the operations of the Partnership Properties and collects cash from sales of production from the Partnership Properties. Consequently, the accompanying Carve-Out Balance Sheets of the Predecessor do not include any cash balances. Cash received or paid by Venoco on behalf of the Predecessor is reflected as net distributions to owner on the accompanying Carve-Out Statements of Changes in Owner's Net Equity.
Oil and Natural Gas Properties—The accompanying carve-out financial statements have been prepared using the full cost method of accounting for oil and natural gas properties. Under this method, all costs incurred in connection with the acquisition of oil and natural gas properties and with the exploration for, and development of, oil and natural gas reserves are capitalized. Proceeds from the disposition of oil and natural gas properties are accounted for as adjustments to the full cost pool, with
F-17
no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Amortization of the capitalized costs of oil and natural gas properties, including estimated future development and abandonment costs, is provided using the equivalent unit-of-production method based upon estimates of proved oil and natural gas reserves. Depletion, depreciation and amortization expense for the years ended December 31, 2004, 2005, and 2006 was $2.3 million, $2.8 million, and $5.5 million, respectively ($3.05, $3.51, and $5.16, respectively, per equivalent barrel of oil).
In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are subject to a ceiling limitation based upon the related estimated future net revenues, discounted at 10 percent, net of tax considerations, plus the lower of cost or estimated fair value of unproved properties. The ceiling limitation is calculated using oil and natural gas prices in effect as of the balance sheet date. At December 31, 2005 and 2006, the net capitalized costs of oil and natural gas properties did not exceed the ceiling limitation.
General and Administrative Expenses—Under the full cost method of accounting, general and administrative expenses that are directly identified with acquisition, exploration and development activities are capitalized to the full cost pool. These capitalized costs include salaries, employee benefits, costs of consulting services and other specifically identifiable costs and do not include costs related to production operations, general corporate overhead or similar activities.
Fair Value of Financial Instruments—Financial instruments included in the accompanying financial statements consist primarily of accrued accounts receivable, accrued liabilities and debt. The carrying value of accrued accounts receivable and accrued liabilities are representative of the fair value due to their short-term maturities. The carrying value of debt approximates its fair value because the stated rate of interest approximates the market.
Income Taxes—The results of the Partnership Properties are currently included in the federal and state returns of Venoco. Following the initial public offering of the Partnership, the Partnership's operations will be treated as a partnership with each partner being separately taxed on its share of our federal taxable income. Therefore, no provision for current or deferred federal income taxes has been provided for in the accompanying carve-out financial statements. However, the Texas Margin tax was signed into law on May 18, 2006, which caused the Texas franchise tax to be applicable to numerous types of entities that previously were not subject to the tax, including the Partnership. A deferred tax liability and related income tax expense was recognized in 2006 for the expected future tax effect of the Texas Margin tax.
Environmental—The Partnership Properties are subject to extensive federal, state and local environmental laws and regulations. These laws and regulations, which regularly change, regulate the discharge of materials into the environment and may require the removal or mitigation of the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.
F-18
Such liabilities are generally recorded at their undiscounted amounts unless the amount and timing of payments is fixed or reliably determinable.
New Accounting Standards—In February 2007, the FASB issued SFAS 159,The Fair Value Option for Financial Assets and Financial Liabilities Including an Amendment of FASB Statement No. 115 ("SFAS 159"), which permits entities to choose to measure many financial instruments and certain other items at fair value (the Fair Value Option). Election of the Fair Value Option is made on an instrument-by-instrument basis and is irrevocable. At the adoption date, unrealized gains and losses on financial assets and liabilities for which the Fair Value Option has been elected would be reported as a cumulative adjustment to beginning retained earnings. If we elect the Fair Value Option for certain financial assets and liabilities, we will report unrealized gains and losses due to changes in fair value in earnings at each subsequent reporting date. The provisions of SFAS 159 are effective January 1, 2008. We are currently assessing the impact, if any, that the adoption of this pronouncement will have on our operating results, financial position and cash flows.
In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements ("SFAS 157"). SFAS 157 establishes a single authoritative definition of fair value, sets out a framework for measuring fair value and requires additional disclosures about fair value measurements. This Standard requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy. SFAS 157 does not require any new fair value measurements, but will remove inconsistencies in fair value measurements between various accounting pronouncements. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The adoption of SFAS 157 is not expected to have a material impact on the financial position or results of operations of the Predecessor. However, additional disclosures may be required about the information used to develop the measurements.
3. ACQUISITIONS OF PROPERTIES
Hastings Complex. On March 31, 2006, Venoco acquired 100% of the members' interest in TexCal Energy (LP) LLC ("TexCal"), an independent exploration and production company with properties in Texas and California. One of the properties acquired in the TexCal acquisition was the Hastings Complex located in East Texas. The Partnership Properties include 50% of Venoco's working interest in the Hastings Complex. The results of operations of the 50% interest in the Hastings Complex have been included in the accompanying carve-out financial statements beginning on March 31, 2006.
In the accompanying carve-out financial statements, the Predecessor's basis in the Hastings Complex at the time of acquisition ($57.7 million) was calculated as a pro rata allocation of Venoco's total acquisition cost of TexCal based on the ratio of the estimated discounted future net revenues related to the Hastings Complex to the total estimated discounted future net revenues acquired by Venoco in its acquisition of TexCal. Asset retirement obligations resulting from the TexCal acquisition were allocated to the Predecessor based on the specific properties included in the Hastings Complex.
The following unaudited pro forma condensed combined operating results for the years ended December 31, 2005 and 2006 give effect to the acquisition of the Hastings Complex as if it had been completed as of January 1 of each year. The pro forma amounts shown below are not necessarily indicative of the operating results that would have occurred if the transaction had occurred on such
F-19
date. The pro forma adjustments made are based on certain assumptions that Venoco believes are reasonable based on currently available information (in thousands) (unaudited).
| | Years Ended December 31,
|
---|
| | 2005
| | 2006
|
---|
Total revenues | | $ | 61,249 | | $ | 71,132 |
Net income | | $ | 24,459 | | $ | 22,448 |
Union Island and Union Island Pipeline. In July 2004, Venoco acquired a working interest in the Union Island field, a producing oil and natural gas property, for $4.6 million. In December 2005, Venoco also purchased the Union Island pipeline for $6.2 million. The acquisitions have been included in the accompanying carve-out financial statements from the dates of acquisition as contributions from Venoco.
4. ASSET RETIREMENT OBLIGATIONS
The asset retirement obligations related to the Predecessor represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing properties and pipelines at the end of their productive lives in accordance with applicable state and federal laws. Asset retirement obligations are determined by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or decrease in the asset retirement obligation and the related capitalized asset retirement costs.
The following table summarizes the changes in asset retirement obligations for the years ended December 31, 2005 and 2006 (in thousands):
| | 2005
| | 2006
| |
---|
Asset retirement obligations at beginning of period | | $ | 8,288 | | $ | 7,869 | |
Revisions of estimated liabilities | | | (1,094 | ) | | 371 | |
Liabilities incurred | | | 61 | | | 2,461 | |
Liabilities settled | | | (13 | ) | | — | |
Accretion expense | | | 627 | | | 716 | |
| |
| |
| |
| Asset retirement obligations at end of period | | | 7,869 | | | 11,417 | |
Less: current asset retirement obligations | | | (28 | ) | | (29 | ) |
| |
| |
| |
| Long-term asset retirement obligations | | $ | 7,841 | | $ | 11,388 | |
| |
| |
| |
Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 5% and 9%. The 2005 revisions primarily relate to extensions in the timing of obligations based on reserve evaluations. The 2006 revisions primarily relate to updated estimates for expected cash outflows and reductions in the timing of obligations based on reserve
F-20
evaluations. Liabilities incurred in 2006 include $2.4 million of asset retirement obligations attributable to the acquisition of the Hastings Complex.
5. DEBT
The accompanying carve-out financial statements reflect an allocation of Venoco's historical debt and debt related costs. As of the dates indicated, the long-term debt allocated to the Predecessor consisted of the following:
| | December 31
|
---|
| | 2005
| | 2006
|
---|
| | (in thousands)
|
---|
Revolving credit facility due March 2009 | | $ | 4,174 | | $ | 5,718 |
Second lien term loan due March 2011 | | | — | | | 44,247 |
| |
| |
|
Total long-term debt | | $ | 4,174 | | $ | 49,965 |
| |
| |
|
Revolving Credit Facility
The accompanying financial statements include a carve-out allocation of debt outstanding on Venoco's revolving credit facility. This allocation was based on the ratio of the estimated discounted future net revenues of the Partnership Properties to the total estimated discounted future net revenues of all of Venoco's oil and gas properties.
Venoco's $300.0 million revolving credit facility is with a syndicate of banks ("revolving credit facility") and has a maturity date of March 30, 2009. The revolving credit facility has a borrowing base of $125.0 million, is secured by a first priority lien on substantially all of Venoco's oil and natural gas properties and other assets, and is unconditionally guaranteed by each of Venoco's subsidiaries other than Ellwood Pipeline, Inc. Base Rate Loans under the revolving credit facility bear interest at a floating rate equal to (i) the greater of a market base rate and the overnight federal funds rate plus 0.50% plus (ii) an applicable margin ranging from zero to 0.75%, based upon utilization. LIBO Rate Loans under the revolving credit facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 1.50% to 2.25%, based upon utilization. A commitment fee ranging from 0.375% to 0.5% per annum is payable with respect to unused borrowing availability under the facility.
Original Second Lien Term Loan Facility
The accompanying financial statements include a carve-out allocation of debt outstanding on Venoco's original senior secured second lien term loan facility (the "original term loan facility"). This allocation was based upon the cash requirements of Venoco's acquisition of TexCal (see Note 3) and the ratio of estimated discounted future net revenues related to the Hastings Complex to the total estimated discounted future net revenues acquired by Venoco in its acquisition of TexCal.
Venoco entered into its original $350.0 million senior secured second lien term loan facility in connection with the acquisition of TexCal. Principal on amounts borrowed under the facility was payable on March 30, 2011. Base Rate Loans under the original term loan facility bear interest at a floating rate equal to (i) the greater of the administrative agent's announced base rate and the
F-21
overnight federal funds rate plus 0.50% plus (ii) 3.50%. LIBO Rate Loans under the original term loan facility bear interest at LIBOR plus 4.50%.
In May 2007, Venoco prepaid and replaced the original term loan facility with a new $500.0 million second lien term loan facility.
The agreements governing the revolving credit facility and original term loan facility contain customary representations, warranties, events of default, indemnities and covenants, including operational covenants that restrict Venoco's ability to incur indebtedness and financial covenants that require Venoco to maintain specified ratios of EBITDA (as defined in the agreement) to interest expense, current assets to current liabilities, debt to EBITDA and PV-10 to total debt. Venoco was in compliance with all of debt covenants as of December 31, 2006.
Debt Issuance Costs
Venoco capitalizes certain direct costs associated with the issuance of long-term debt. The accompanying financial statements reflect an allocation of a portion of deferred loan costs based on the ratio of the estimated discounted future net revenues of the Partnership Properties to the total estimated discounted future net revenues of all of Venoco's oil and gas properties.
6. INCOME TAXES
No provision for federal or state income taxes is made in the accompanying financial statements, except for the Texas Margin tax, because the taxable income or loss will be included in the income tax returns of the individual partners of the Partnership with the exception of Texas Margin taxes.
Following is a reconciliation between the statutory federal income tax rate and the effective income tax rate as if income taxes were included in the financial statements:
| | 2004
| | 2005
| | 2006
| |
---|
Statutory rate | | 35.0 | % | 35.0 | % | 35.0 | % |
State income tax net of federal benefit | | 5.4 | | 5.6 | | 4.8 | |
| |
| |
| |
| |
Effective rate | | 40.4 | % | 40.6 | % | 39.8 | % |
| |
| |
| |
| |
F-22
The following table reconciles net income before income taxes to pro forma federal taxable income for the periods indicated (in thousands) (unaudited):
| | Years Ended December 31,
| |
---|
| | 2004
| | 2005
| | 2006
| |
---|
Net income before taxes | | $ | 13,909 | | $ | 21,443 | | $ | 21,399 | |
Depletion, depreciation and amortization for financial reporting purposes | | | 2,812 | | | 3,397 | | | 6,258 | |
Depletion, depreciation and amortization for tax reporting purposes | | | (2,185 | ) | | (2,459 | ) | | (9,497 | ) |
IDC expensed for tax reporting purposes | | | (424 | ) | | (1,827 | ) | | (4,491 | ) |
| |
| |
| |
| |
Pro forma federal taxable income | | $ | 14,112 | | $ | 20,554 | | $ | 13,669 | |
| |
| |
| |
| |
The following table details pro forma net income as if a tax provision was calculated for the Predecessor on a separate return basis (in thousands) (unaudited):
| | Years Ended December 31,
| |
---|
| | 2004
| | 2005
| | 2006
| |
---|
Net income before taxes | | $ | 13,909 | | $ | 21,443 | | $ | 21,399 | |
Tax provision | | | (5,618 | ) | | (8,604 | ) | | (8,317 | ) |
| |
| |
| |
| |
Pro forma net income | | $ | 8,291 | | $ | 12,839 | | $ | 13,082 | |
| |
| |
| |
| |
7. CONTINGENCIES
Litigation
Prior to the closing of the Offering, Venoco and the Partnership will enter into an omnibus agreement pursuant to which Venoco will indemnify the Partnership:
- (i)
- for a period of one year against potential environmental claims, losses and expenses associated with the operation of the Partnership Properties occurring before the closing, other than such claims made as a result of additions to or modifications of environmental laws promulgated after the closing,
- (ii)
- for claims, losses and expenses attributable to title defects, retained assets and liabilities (including any pre-closing litigation relating to contributed assets) and income taxes attributable to pre-closing operations,
- (iii)
- for claims, losses and expenses arising from certain litigation related to one of the Partnership Properties (Beverly Hills) to the extent those liabilities are attributable to operations of the assets prior to the closing,
provided, Venoco's maximum liability for the indemnification obligations described in (i) and (ii), above, will be limited to $10 million and Venoco will not have any obligation until the Partnership's aggregate losses under (i) and (ii), above, exceed $500,000.
F-23
Immediately after closing the Partnership will not be a party to any claims or legal actions. The Partnership believes that the indemnity obligations of Venoco will be adequate to protect it from any claims or legal actions related to the Partnership Properties arising after closing but related to ownership or operation of the Partnership Properties prior to closing.
CO2 Project with Denbury
In November 2006, Venoco entered into an option agreement with Denbury Resources, Inc. ("Denbury") relating to a potential CO2 enhanced recovery project in the Hastings Complex. Pursuant to the agreement, Denbury will pay Venoco a total of $50.0 million for an option to acquire the Partnership's and Venoco's interest in parts of the complex and certain related property for use in an enhanced recovery project in which Venoco will have a continuing interest. Of the total option payment, $37.5 million was paid in December 2006, $7.5 million will be paid in November 2007 and the remaining $5.0 million will be paid in November 2008. In accordance with its accounting policies, the Predecessor did not recognize a gain on sale for financial reporting purposes, but applied its share of the $50.0 million in option payments to reduce the capitalized cost of its oil and natural gas properties and recorded current receivables of $3.75 million for the payment to be received in November 2007 and non-current receivables of $2.5 million for the payment to be received in November 2008.
Denbury may not exercise the option prior to September 2008 and the initial exercise period will end in October 2009, subject to Denbury's right to extend it for successive one-year periods until 2016 for an annual extension fee of $30.0 million payable to Venoco. Pursuant to the agreement, Denbury has an option to acquire the Partnership's and Venoco's interests in the Hastings Complex in exchange for either a lump-sum cash payment or a right to receive a stream of payments under a volumetric production payment or similar arrangement. If the option is exercised, Venoco will determine whether the consideration will take the form of a lump-sum cash payment or a volumetric production payment or similar arrangement. If Venoco elects to receive a lump-sum payment, the Partnership will receive its proportionate share of those proceeds. If Venoco elects to receive a volumetric production payment or similar arrangement, the Partnership would retain commodity price risk with respect to production from the Hastings Complex and would depend on Denbury's performance of its obligations under the payment arrangement for its operating cash flow from this asset. In addition, Venoco and Denbury could agree to amend the option agreement.
8. RELATED PARTY TRANSACTIONS
The Predecessor does not have its own employees. The employees supporting the operations of the Partnership Properties are employees of Venoco. Accordingly, Venoco recognizes all employee-related liabilities in its consolidated financial statements. In addition to employee payroll-related expenses, Venoco incurred general and administrative expenses related to leasing of office space and other corporate overhead type expenses during the period covered by the accompanying carve-out financial statements. For purposes of deriving the accompanying carve-out financial statements, a portion of the consolidated general and administrative expenses reported for Venoco has been allocated to the Predecessor and included in the accompanying carve-out Statements of Operations for each of the three years presented. The portion of Venoco's consolidated general and administrative expenses included in the accompanying carve-out financial statements for each period presented was determined
F-24
based on the respective percentage of Boe produced by the Predecessor in relation to the total Boe produced by Venoco on a consolidated basis.
9. SUBSEQUENT EVENT
West Montalvo Onshore Acquisition. In May 2007, Venoco acquired the West Montalvo field from an unrelated party. The onshore portion of the West Montalvo field has been included in the Partnership Properties. The results of operations from the onshore portion of the West Montalvo field have been included in the Predecessor's carve-out financial statements beginning on May 11, 2007.
The Predecessor's basis in the onshore portion of the West Montalvo field at the time of acquisition ($37.0 million) was calculated as a pro rata allocation of Venoco's total acquisition cost of the West Montalvo field based on the ratio of the estimated discounted future net revenues related to the onshore portion of the field to the total estimated discounted future net revenues of the field. Asset retirement obligations resulting from the West Montalvo acquisition were allocated to the Predecessor based on the specific properties included in the onshore portion of the field.
10. CARVE-OUT SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION ACTIVITIES (UNAUDITED)
The following information concerning the Predecessor's oil and natural gas operations has been provided pursuant to SFAS No. 69,Disclosures about Oil and Gas Producing Activities. At December 31, 2006, the Predecessor's oil and natural gas producing activities were conducted onshore within the continental United States and offshore in federal and state waters off the coast of California.
| | As of December 31,
| |
---|
| | 2004
| | 2005
| | 2006
| |
---|
| | (in thousands)
| |
---|
Properties not subject to amortization: | | | | | | | | | | |
| Deposit for purchase of properties | | $ | 1,320 | | $ | — | | $ | — | |
Properties subject to amortization | | | 53,480 | | | 59,491 | | | 107,877 | |
| |
| |
| |
| |
Total capitalized costs | | | 54,800 | | | 59,491 | | | 107,877 | |
Accumulated depletion, depreciation and amortization | | | (19,183 | ) | | (21,954 | ) | | (27,496 | ) |
| |
| |
| |
| |
Net capitalized costs | | $ | 35,617 | | $ | 37,537 | | $ | 80,381 | |
| |
| |
| |
| |
F-25
Costs incurred for oil and natural gas acquisition, exploitation and development are summarized below.
| | For the Years Ended December 31,
|
---|
| | 2004
| | 2005
| | 2006
|
---|
| | (in thousands)
|
---|
Property acquisition and leasehold costs: | | | | | | | | | |
| Deposit for purchase of properties | | $ | 1,320 | | $ | — | | $ | — |
| Proved property | | | 4,625 | | | 6,238 | | | 32,749 |
Exploration costs | | | 74 | | | 172 | | | — |
Development costs | | | 948 | | | 635 | | | 12,805 |
| |
| |
| |
|
Total costs incurred | | $ | 6,967 | | $ | 7,045 | | $ | 45,554 |
| |
| |
| |
|
The following table sets forth the net proved reserves for the Partnership Properties, including changes, and proved developed reserves (all within the United States) at the end of each of the three years in the periods ended December 31, 2004, 2005 and 2006.
| | Crude Oil, Liquids and Condensate (MBbl)
| | Natural Gas (MMcf)
| |
---|
| | 2004(3)
| | 2005(2)
| | 2006(1)
| | 2004(3)
| | 2005(2)
| | 2006(1)
| |
---|
Beginning of the year reserves | | 12,745 | | 8,438 | | 8,802 | | 9,187 | | 7,869 | | 16,372 | |
Revisions of previous estimates | | (4,008 | ) | 801 | | 532 | | (807 | ) | 1,349 | | (260 | ) |
Extensions, discoveries and improved recovery | | 329 | | 170 | | — | | 250 | | 258 | | — | |
Purchases of reserves in place | | — | | — | | 5,720 | | — | | 7,986 | | — | |
Production | | (628 | ) | (607 | ) | (905 | ) | (761 | ) | (1,090 | ) | (1,009 | ) |
| |
| |
| |
| |
| |
| |
| |
End of year reserves | | 8,438 | | 8,802 | | 14,149 | | 7,869 | | 16,372 | | 15,103 | |
| |
| |
| |
| |
| |
| |
| |
Proved developed reserves: | | | | | | | | | | | | | |
| Beginning of year | | 9,500 | | 7,403 | | 7,204 | | 7,706 | | 6,361 | | 12,610 | |
| End of year | | 7,403 | | 7,204 | | 13,013 | | 6,361 | | 12,610 | | 12,503 | |
- (1)
- Based on unescalated prices of (i) $54.34 per Bbl for oil and natural gas liquids, adjusted for quality, transportation fees and regional price differentials and (ii) $4.83 per Mcf for natural gas, adjusted for energy content, transportation fees and regional price differentials.
- (2)
- Based on unescalated prices of $52.00 per Bbl for oil and natural gas liquids and $8.94 per Mcf for natural gas, adjusted, in each case, as described in (1) above.
- (3)
- Based on unescalated prices of $39.40 per Bbl for oil and natural gas liquids and $6.42 per MMBtu for natural gas, adjusted, in each case, as described in (1) above.
F-26
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following summarizes the policies used in the preparation of the accompanying oil and natural gas reserve disclosures, standardized measures of discounted future net cash flows from proved oil and natural gas reserves and the reconciliations of standardized measures from year to year. The information disclosed, as prescribed by the Statement of Financial Accounting Standards No. 69, is an attempt to present the information in a manner comparable with industry peers.
The information is based on estimates of proved reserves attributable to the Predecessor's interest in oil and natural gas properties as of December 31 of the years presented. The information is derived from estimates prepared by independent petroleum engineers. Proved reserves are estimated quantities of oil and natural 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.
The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:
(1) Estimates are made of quantities of proved reserves and future periods during which they are expected to be produced based on year-end economic conditions.
(2) The estimated future cash flows are compiled by applying year-end prices of oil and natural gas to the year-end quantities of proved reserves.
(3) The future cash flows are reduced by estimated production costs, costs to develop and produce the proved reserves and abandonment costs, all based on year-end economic conditions.
(4) Future income tax expenses are based on year-end statutory tax rates giving effect to the remaining tax basis in the oil and natural gas properties, other deductions, credits and allowances relating to the Predecessor's proved oil and natural gas reserves.
(5) Future net cash flows are discounted to present value by applying a discount rate of 10%.
The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair value of the Predecessor's oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates.
F-27
The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows and does not include cash flows associated with hedges outstanding at each of the respective reporting dates.
| | As of December 31,
| |
---|
| | 2004
| | 2005
| | 2006
| |
---|
| | (In thousands)
| |
---|
Future cash inflows | | $ | 382,953 | | $ | 604,054 | | $ | 841,700 | |
Future production costs | | | (205,021 | ) | | (263,818 | ) | | (454,560 | ) |
Future development costs | | | (21,463 | ) | | (25,080 | ) | | (31,979 | ) |
Future income taxes | | | — | | | — | | | (1,547 | ) |
| |
| |
| |
| |
Future net cash flows | | | 156,469 | | | 315,156 | | | 353,614 | |
10% annual discount for estimated timing of cash flows | | | (53,710 | ) | | (128,605 | ) | | (144,625 | ) |
| |
| |
| |
| |
Standardized measure of discounted future net cash flows | | $ | 102,759 | | $ | 186,551 | | $ | 208,989 | |
| |
| |
| |
| |
The following table summarizes changes in the standardized measure of discounted future net cash flows.
| | As of December 31,
| |
---|
| | 2004
| | 2005
| | 2006
| |
---|
| | (In thousands)
| |
---|
Beginning of the year | | $ | 74,731 | | $ | 102,759 | | $ | 186,551 | |
Changes in prices and production costs | | | 55,566 | | | 67,640 | | | (50,799 | ) |
Revisions of previous quantity estimates | | | (49,836 | ) | | 17,856 | | | 6,825 | |
Changes in future development costs | | | 2,198 | | | (2,606 | ) | | (10,471 | ) |
Development costs incurred during the period | | | 1,021 | | | 786 | | | 10,819 | |
Extensions, discoveries and improved recovery, net of related costs | | | 4,459 | | | 3,708 | | | — | |
Sales of oil and natural gas, net of production costs | | | (14,607 | ) | | (22,919 | ) | | (32,536 | ) |
Accretion of discount | | | 7,473 | | | 10,276 | | | 18,655 | |
Net change in income taxes | | | — | | | — | | | (914 | ) |
Purchases of reserves in place | | | — | | | 23,168 | | | 79,886 | |
Production timing and other | | | 21,754 | | | (14,117 | ) | | 973 | |
| |
| |
| |
| |
End of year | | $ | 102,759 | | $ | 186,551 | | $ | 208,989 | |
| |
| |
| |
| |
F-28
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
CARVE-OUT BALANCE SHEETS (UNAUDITED)
(In thousands)
| | December 31, 2006
| | September 30, 2007
| |
---|
CURRENT ASSETS: | | | | | | | |
| Accrued accounts receivable | | $ | 10,385 | | $ | 11,289 | |
| |
| |
| |
| | Total current assets | | | 10,385 | | | 11,289 | |
| |
| |
| |
PROPERTY, PLANT AND EQUIPMENT, AT COST: | | | | | | | |
| Oil and natural gas properties, full-cost method | | | 107,878 | | | 180,843 | |
| Accumulated depletion, depreciation and amortization | | | (27,496 | ) | | (34,943 | ) |
| |
| |
| |
| | Net property, plant and equipment | | | 80,382 | | | 145,900 | |
| |
| |
| |
OTHER ASSETS | | | 4,296 | | | 3,599 | |
| |
| |
| |
| | TOTAL ASSETS | | $ | 95,063 | | $ | 160,788 | |
| |
| |
| |
LIABILITIES AND OWNER'S NET EQUITY | | | | | | | |
CURRENT LIABILITIES: | | | | | | | |
| Accrued liabilities | | $ | 7,366 | | $ | 16,369 | |
| Current taxes payable | | | — | | | 42 | |
| Current asset retirement obligations | | | 29 | | | 496 | |
| |
| |
| |
| | Total current liabilities | | | 7,395 | | | 16,907 | |
| |
| |
| |
DEBT | | | 49,965 | | | 83,141 | |
DEFERRED INCOME TAXES | | | 14 | | | 62 | |
ASSET RETIREMENT OBLIGATIONS | | | 11,388 | | | 12,883 | |
| |
| |
| |
| Total liabilities | | | 68,762 | | | 112,993 | |
| |
| |
| |
COMMITMENTS AND CONTINGENCIES | | | | | | | |
OWNER'S NET EQUITY | | | 26,301 | | | 47,795 | |
| |
| |
| |
| | TOTAL LIABILITIES AND OWNER'S NET EQUITY | | $ | 95,063 | | $ | 160,788 | |
| |
| |
| |
See Notes to Unaudited Carve-Out Financial Statements.
F-29
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
CARVE-OUT STATEMENTS OF OPERATIONS (UNAUDITED)
(In thousands)
| | Nine Months Ended September 30,
|
---|
| | 2006
| | 2007
|
---|
REVENUES: | | | | | | |
| Oil and natural gas sales | | $ | 42,739 | | $ | 56,056 |
| Pipeline fees | | | 5,767 | | | 5,695 |
| |
| |
|
| | Total revenue | | | 48,506 | | | 61,751 |
| |
| |
|
EXPENSES: | | | | | | |
| Lease operating expense | | | 17,410 | | | 22,617 |
| Production and property taxes | | | 936 | | | 1,249 |
| Transportation expense | | | 695 | | | 684 |
| Pipeline operating expense | | | 1,799 | | | 1,536 |
| Depletion, depreciation and amortization | | | 4,293 | | | 7,447 |
| Accretion of asset retirement obligations | | | 524 | | | 682 |
| General and administrative expense | | | 2,763 | | | 3,696 |
| |
| |
|
| | Total expenses | | | 28,420 | | | 37,911 |
| |
| |
|
Income from operations | | | 20,086 | | | 23,840 |
FINANCING COSTS: | | | | | | |
| Interest expense | | | 3,411 | | | 5,139 |
| Amortization of deferred loan costs | | | 470 | | | 412 |
| Loss on extinguishment of debt | | | — | | | 1,061 |
| |
| |
|
| | Total financing costs | | | 3,881 | | | 6,612 |
| |
| |
|
Income before income taxes | | | 16,205 | | | 17,228 |
Income tax provision | | | 12 | | | 91 |
| |
| |
|
Net income | | $ | 16,193 | | $ | 17,137 |
| |
| |
|
See Notes to Unaudited Carve-Out Financial Statements.
F-30
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
CARVE-OUT STATEMENTS OF CASH FLOWS (UNAUDITED)
(In thousands)
| | Nine Months Ended September 30,
| |
---|
| | 2006
| | 2007
| |
---|
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | |
| Net income | | $ | 16,193 | | $ | 17,137 | |
| Adjustments to reconcile net income to cash provided by operating activities: | | | | | | | |
| | Depletion, depreciation and amortization | | | 4,293 | | | 7,447 | |
| | Accretion of asset retirement obligation | | | 524 | | | 682 | |
| | Deferred income taxes | | | 12 | | | 49 | |
| | Amortization of deferred loan costs | | | 470 | | | 412 | |
| | Loss on extinguishment of debt | | | — | | | 1,061 | |
| Changes in operating assets and liabilities, net: | | | | | | | |
| | Accrued accounts receivable | | | (1,721 | ) | | (903 | ) |
| | Accrued liabilities | | | 1,863 | | | 813 | |
| | Current taxes payable | | | — | | | 42 | |
| |
| |
| |
| | | Net cash provided by operating activities | | | 21,634 | | | 26,740 | |
| |
| |
| |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | |
| Expenditures for oil and natural gas properties | | | (4,413 | ) | | (26,530 | ) |
| Acquisitions of oil and natural gas properties | | | (57,750 | ) | | (36,967 | ) |
| |
| |
| |
| | | Net cash used in investing activities | | | (62,163 | ) | | (63,497 | ) |
| |
| |
| |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | |
| Proceeds from debt | | | 75,372 | | | 33,176 | |
| Deferred loan costs | | | (2,019 | ) | | (776 | ) |
| Contributions from (distributions to) parent | | | (32,824 | ) | | 4,357 | |
| |
| |
| |
| | | Net cash provided by financing activities | | | 40,529 | | | 36,757 | |
| |
| |
| |
| Net change in cash and cash equivalents | | | — | | | — | |
| Cash and cash equivalents, beginning of period | | | — | | | — | |
| |
| |
| |
| Cash and cash equivalents, end of period | | $ | — | | $ | — | |
| |
| |
| |
See Notes to Unaudited Carve-Out Financial Statements.
F-31
VENOCO ACQUISITION COMPANY, L.P. PREDECESSOR
NOTES TO UNAUDITED CARVE-OUT FINANCIAL STATEMENTS
NINE MONTHS ENDED SEPTEMBER 30, 2006 AND 2007
1. ORGANIZATION, BASIS OF PRESENTATION AND NATURE OF OPERATIONS
Venoco Acquisition Company, L.P. (the "Partnership") is a Delaware limited partnership formed on September 25, 2007 by Venoco, Inc. ("Venoco") to acquire interests in certain oil and natural gas producing properties and related assets principally located onshore and offshore of southern California and onshore Texas (the "Partnership Properties"). Venoco currently owns all the general and limited partner interests in the Partnership. The Partnership intends to pursue an initial public offering of its common units representing limited partner interests (the "Offering"). At the closing of the Offering, Venoco will contribute the Partnership Properties to the Partnership in exchange for cash, common units and subordinated units representing a 55.4% limited partner interest, a 2% general partner interest and cash (the "Formation Transactions").
The accompanying carve-out financial statements and related notes thereto represent the carve-out financial position, results of operations, cash flows, and changes in owner's net investment of the Partnership Properties. The carve-out financial statements have been prepared in accordance with Regulation S-X, Article 3 "General instructions as to financial statements" and Staff Accounting Bulletin ("SAB") Topic 1-B "Allocations of Expenses and Related Disclosure in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity" and represent the Partnership's predecessor, referred to herein as Venoco Acquisition Company, L.P. Predecessor (the "Predecessor"). Certain costs and expenses incurred by Venoco are only indirectly attributable to its ownership of the Partnership Properties as Venoco owns interests in other oil and natural gas properties. As a result, certain assumptions and estimates were made in order to allocate a reasonable share of such costs and expenses to Venoco Acquisition Company Predecessor, so that the accompanying carve-out financial statements reflect substantially all the costs of doing business. These allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if the Predecessor had been operated as a stand-alone entity.
The accompanying unaudited carve-out financial statements have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and note disclosures normally included in annual financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to those rules and regulations, although management believes that the disclosures made are adequate to make the information not misleading."
2. ACQUISITIONS OF PROPERTIES
Hastings Complex. On March 31, 2006, Venoco acquired 100% of the members' interest in TexCal Energy (LP) LLC ("TexCal"), an independent exploration and production company with properties in Texas and California. One of the properties acquired in the TexCal acquisition was the Hastings Complex located in East Texas. The Partnership Properties include 50% of Venoco's working interest in the Hastings Complex. The results of operations from the Hastings Complex have been included in the accompanying carve-out financial statements beginning on March 31, 2006.
In the accompanying carve-out financial statements, the Predecessor's basis in the Hastings Complex at the time of acquisition ($57.7 million) was calculated as a pro rata allocation of Venoco's total acquisition cost of TexCal based on the ratio of the estimated discounted future net revenues related to the Hastings Complex to the total estimated discounted future net revenues acquired by Venoco in its acquisition of TexCal. Asset retirement obligations resulting from the TexCal acquisition were allocated to the Predecessor based on the specific properties included in the Hastings Complex.
F-32
West Montalvo Onshore Acquisition. In May 2007, Venoco acquired the West Montalvo field from an unrelated party. The onshore portion of the West Montalvo field has been included in the Partnership Properties. The results of operations from the onshore portion of the West Montalvo field have been included in the accompanying carve-out financial statements beginning on May 11, 2007.
The Predecessor's basis in the onshore portion of the West Montalvo field at the time of acquisition ($37.0 million) was calculated as a pro rata allocation of Venoco's total acquisition cost of the West Montalvo field based on the ratio of the estimated discounted future net revenues related to the onshore portion of the field to the total estimated discounted future net revenues of the field. Asset retirement obligations resulting from the West Montalvo acquisition were allocated to the Predecessor based on the specific properties included in the onshore portion of the field.
The following unaudited pro forma operating results for the nine months ended September 30, 2006 and 2007 give effect to the Hastings Complex acquisition as if it had been completed on January 1, 2006 and the West Montalvo acquisition as if it had been completed on January 1 of each period. The pro forma amounts shown below are not necessarily indicative of the operating results that would have occurred if the transactions had occurred on such dates. The pro forma adjustments made are based on certain assumptions that Venoco believes are reasonable based on currently available information (in thousands) (unaudited).
| | Nine Months Ended September 30,
|
---|
| | 2006
| | 2007
|
---|
Total revenues | | $ | 61,428 | | $ | 64,729 |
Net income | | $ | 16,984 | | $ | 17,077 |
3. DEBT
The accompanying carve-out financial statements reflect an allocation of Venoco's historical debt and debt related costs. As of the dates indicated, the long-term debt allocated to the Predecessor consisted of the following:
| | December 31, 2006
| | September 30, 2007
|
---|
| | (in thousands)
|
---|
Revolving credit facility due March 2009 | | $ | 5,718 | | $ | 1,927 |
Original term loan due March 2011 | | | 44,247 | | | — |
New term loan due May 2014 | | | — | | | 81,214 |
| |
| |
|
Total long-term debt | | $ | 49,965 | | $ | 83,141 |
| |
| |
|
Revolving Credit Facility
The accompanying financial statements include a carve-out allocation of debt outstanding on Venoco's revolving credit facility. This allocation was based on the ratio of the estimated discounted future net revenues of the Partnership Properties to the total estimated discounted future net revenues of all of Venoco's oil and gas properties.
Venoco's $300.0 million revolving credit facility is with a syndicate of banks ("revolving credit facility") and has a maturity date of March 30, 2009. The revolving credit facility has a borrowing base of $125.0 million, is secured by a first priority lien on substantially all of Venoco's oil and natural gas
F-33
properties and other assets, and is unconditionally guaranteed by each of Venoco's subsidiaries other than Ellwood Pipeline, Inc. Base Rate Loans under the revolving credit facility bear interest at a floating rate equal to (i) the greater of a market base rate and the overnight federal funds rate plus 0.50% plus (ii) an applicable margin ranging from zero to 0.75%, based upon utilization. LIBO Rate Loans under the revolving credit facility bear interest at (i) LIBOR plus (ii) an applicable margin ranging from 1.50% to 2.25%, based upon utilization. A commitment fee ranging from 0.375% to 0.5% per annum is payable with respect to unused borrowing availability under the facility.
The agreement governing the facility contains customary representations, warranties, events of default, indemnities and covenants, including operational covenants that restrict Venoco's ability to incur indebtedness and financial covenants that require Venoco to maintain specified ratios of EBITDA (as defined in the agreement) to interest expense, current assets to current liabilities, debt to EBITDA and PV-10 to total debt. As of September 30, 2007, Venoco was in compliance with all of its debt covenants under the revolving credit facility.
Second Lien Term Loan Facility
The accompanying financial statements include a carve-out allocation of debt outstanding on Venoco's original second lien term loan facility (the "original term loan facility"). This allocation was based upon the cash requirements of Venoco's acquisition of TexCal (see Note 2) and the ratio of estimated discounted future net revenues related to the Hastings Complex to the total estimated discounted future net revenues acquired by Venoco in its acquisition of TexCal.
Venoco entered into its original $350.0 million senior secured second lien term loan facility in connection with the acquisition of TexCal. Principal on amounts borrowed under the facility was payable on March 30, 2011. In May 2007, Venoco prepaid and replaced this facility with a new $500.0 million second lien term loan facility (the "new term loan facility"). In connection with the settlement of the original term loan facility, Venoco paid a prepayment premium and wrote off related deferred loan costs. A portion of those amounts have been included in the accompanying financial statements and are reflected as loss on extinguishment of debt in the statement of operations.
Loans made under the new facility are designated, at Venoco's option, as either "Base Rate Loans" or "LIBO Rate Loans." Base Rate Loans bear interest at a floating rate equal to (i) the greater of the overnight federal funds rate plus 0.50% and a market base rate, plus (ii) 3.00%. LIBO Rate Loans bear interest at LIBOR plus 4.00%.
The new term loan agreement contains customary representations, warranties, events of default and indemnities and certain customary covenants, including covenants that restrict Venoco's ability to incur additional indebtedness. The new facility is secured by second priority liens on substantially all of Venoco's oil and natural gas properties and other assets, including the stock of all of its subsidiaries, and is unconditionally guaranteed by each of Venoco's subsidiaries other than Ellwood Pipeline, Inc. Principal on the new facility is payable on May 8, 2014. However, if Venoco's senior notes are not refinanced in full prior to September 20, 2011, principal on the new facility will be payable on that date.
4. ASSET RETIREMENT OBLIGATIONS
The asset retirement obligations related to Venoco Acquisition Company, L.P. Predecessor represent the estimated present value of the amounts expected to be incurred to plug, abandon and remediate producing properties (including removal of certain onshore and offshore facilities in
F-34
California) at the end of their productive lives in accordance with applicable state and federal laws. Asset retirement obligations are determined by calculating the present value of estimated cash flows related to plugging and abandonment liabilities. The asset retirement liability is accreted to its present value each period and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. Changes resulting from revisions to the timing or the amount of the original estimate of undiscounted cash flows are recognized as an increase or decrease in the asset retirement obligation and the related capitalized asset retirement costs.
The following table summarizes the changes in asset retirement obligations for the nine months ended September 30, 2006 and 2007 (in thousands):
| | 2006
| | 2007
| |
---|
Asset retirement obligations at beginning of period | | $ | 7,869 | | $ | 11,418 | |
Revisions of estimated liabilities | | | — | | | 177 | |
Liabilities incurred | | | 2,211 | | | 1,102 | |
Liabilities settled | | | — | | | — | |
Accretion expense | | | 524 | | | 682 | |
| |
| |
| |
| Asset retirement obligations at end of period | | | 10,604 | | | 13,379 | |
Less: current asset retirement obligations | | | (314 | ) | | (496 | ) |
| |
| |
| |
| Long-term asset retirement obligations | | $ | 10,290 | | $ | 12,883 | |
| |
| |
| |
Discount rates used to calculate the present value vary depending on the estimated timing of the obligation, but typically range between 5% and 9%. Liabilities incurred in 2006 and 2007 are primarily the result of the acquisitions of the Hastings Complex and the onshore portion of the West Montalvo field, respectively.
5. CONTINGENCIES
Litigation
Prior to the closing of the Offering, Venoco and the Partnership will enter into an omnibus agreement pursuant to which Venoco will indemnify the Partnership:
- (i)
- for a period of one year against potential environmental claims, losses and expenses associated with the operation of the Partnership Properties occurring before the closing, other than such claims made as a result of additions to or modifications of environmental laws promulgated after the closing,
- (ii)
- for claims, losses and expenses attributable to title defects, retained assets and liabilities (including any pre-closing litigation relating to contributed assets) and income taxes attributable to pre-closing operations,
- (iii)
- for claims, losses and expenses arising from certain litigation related to one of the Partnership Properties (Beverly Hills) to the extent those liabilities are attributable to operations of the assets prior to the closing,
provided, Venoco's maximum liability for the indemnification obligations described in (i) and (ii), above, will be limited to $10 million and Venoco will not have any obligation until the Partnership's aggregate losses under (i) and (ii), above, exceed $500,000.
F-35
Immediately after closing the Partnership will not be a party to any claims or legal actions. The Partnership believes that the indemnity obligations of Venoco will be adequate to protect it from any claims or legal actions related to the Partnership Properties arising after closing but related to ownership or operation of the Partnership Properties prior to closing.
CO2 Project with Denbury
In November 2006, Venoco entered into an option agreement with Denbury Resources, Inc. ("Denbury") relating to a potential CO2 enhanced recovery project in the Hastings Complex. Pursuant to the agreement, Denbury will pay Venoco a total of $50.0 million for an option to acquire the Partnership's and Venoco's interest in parts of the complex and certain related property for use in an enhanced recovery project in which Venoco will have a continuing interest. Of the total option payment, $37.5 million was paid in December 2006, $7.5 million will be paid in November 2007 and the remaining $5.0 million will be paid in November 2008. In accordance with its accounting policies, the Predecessor did not recognize a gain on sale for financial reporting purposes, but applied its share of the $50.0 million in option payments to reduce the capitalized cost of its oil and natural gas properties and recorded current receivables of $3.75 million for the payment to be received in November 2007 and non-current receivables of $2.5 million for the payment to be received in November 2008.
Denbury may not exercise the option prior to September 2008 and the initial exercise period will end in October 2009, subject to Denbury's right to extend it for successive one-year periods until 2016 for an annual extension fee of $30.0 million payable to Venoco. Pursuant to the agreement, Denbury has an option to acquire the Partnership's and Venoco's interests in the Hastings Complex in exchange for either a lump-sum cash payment or a right to receive a stream of payments under a volumetric production payment or similar arrangement. If the option is exercised, Venoco will determine whether the consideration will take the form of a lump-sum cash payment or a volumetric production payment or similar arrangement. If Venoco elects to receive a lump-sum payment, the Partnership will receive its proportionate share of those proceeds. If Venoco elects to receive a volumetric production payment or similar arrangement, the Partnership would retain commodity price risk with respect to production from the Hastings Complex and would depend on Denbury's performance of its obligations under the payment arrangement for its operating cash flow from this asset. In addition, Venoco and Denbury could agree to amend the option agreement.
6. RELATED PARTY TRANSACTIONS
The Predecessor does not have its own employees. The employees supporting the operations of the Predecessor are employees of Venoco. Accordingly, Venoco recognizes all employee-related liabilities in its consolidated financial statements. In addition to employee payroll-related expenses, Venoco incurred general and administrative expenses related to leasing of office space and other corporate overhead type expenses during the period covered by the accompanying carve-out financial statements. For purposes of deriving the accompanying carve-out financial statements, a portion of the consolidated general and administrative expenses reported for Venoco has been allocated to the Predecessor and included in the accompanying carve-out Statements of Operations for each period presented. The portion of Venoco's consolidated general and administrative expenses to be included in the accompanying carve-out financial statements for each period presented was determined based on the respective percentage of Boe produced by the Predecessor in relation to the total Boe produced by Venoco on a consolidated basis.
F-36
VENOCO ACQUISITION COMPANY L.P.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Venoco, Inc.
Denver, Colorado
We have audited the accompanying balance sheet of Venoco Acquisition Company L.P. (the "Partnership") as of February 8, 2008. This financial statement is the responsibility of the Partnership's management. Our responsibility is to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Venoco Acquisition Company L.P. as of February 8, 2008, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 11, 2008
F-37
VENOCO ACQUISITION COMPANY, L.P.
BALANCE SHEET
| | February 8, 2008
|
---|
ASSETS | | | |
CURRENT ASSETS: | | | |
| Cash | | $ | 1,000 |
| |
|
| | Total assets | | $ | 1,000 |
| |
|
PARTNERS' EQUITY | | | |
PARTNERS' EQUITY: | | | |
| General partner | | $ | 20 |
| Limited partner | | | 980 |
| |
|
TOTAL PARTNERS' EQUITY | | $ | 1,000 |
| |
|
See Notes to Balance Sheet.
F-38
VENOCO ACQUISITION COMPANY, L.P.
NOTES TO BALANCE SHEET
Note 1. Formation of Partnership and Basis of Presentation
Venoco Acquisition Company, L.P., a Delaware partnership (the "Partnership"), was formed on September 25, 2007, to acquire, exploit, and develop oil and natural gas properties and to acquire, own, and operate related assets. Venoco Acquisition Company GP, LLC, a Delaware limited liability company (the "General Partner"), currently holds a 2% general partner interest in the Partnership, and Venoco Acquisition Company, L.P. Holdings LLC, a Delaware limited liability company (the "Limited Partner"), currently holds a 98% limited partner interest in the Partnership. Both the General Partner and the Limited Partner are wholly owned subsidiaries of Venoco, Inc., a publicly traded Delaware corporation ("Venoco").
On February 8, 2008, the General Partner contributed $20 to the Partnership in exchange for its 2% general partner interest and the Limited Partner contributed $980 to the Partnership in exchange for its 98% limited partner interest in the Partnership.
There were no other transactions involving the Partnership as of February 8, 2008.
Note 2. Subsequent Events (Unaudited)
The Partnership intends to offer common units, representing limited partner interests to the public in an offering registered under the Securities Act of 1933, as amended. Concurrently, Venoco will transfer certain oil and natural gas properties located in California and onshore Texas to the Partnership in exchange for common units; the Limited Partner's existing limited partner interest in the Partnership will be converted into common units; and the Partnership will issue to the General Partner, an initial 2% general partner interest in the Partnership.
F-39
VENOCO ACQUISITION COMPANY GP, LLC
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors of
Venoco, Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheet of Venoco Acquisition Company GP, LLC (the "Company") as of February 8, 2008. This financial statement is the responsibility of the Company's management. Our responsibility is to express an opinion on this financial statement based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of Venoco Acquisition Company GP, LLC as of February 8, 2008, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
February 11, 2008
F-40
VENOCO ACQUISITION COMPANY GP, LLC
CONSOLIDATED BALANCE SHEET
| | February 8, 2008
|
---|
ASSETS | | | |
| Cash | | $ | 1,980 |
| |
|
| | Total assets | | $ | 1,980 |
| |
|
LIABILITIES AND OWNER'S EQUITY | | | |
| Minority interest | | $ | 980 |
| Owner's equity: | | | |
| | Contributed capital | | | 1,000 |
| |
|
| | Total owner's equity | | | 1,000 |
| |
|
| | Total liabilities and owner's equity | | $ | 1,980 |
| |
|
See Notes to Consolidated Balance Sheet.
F-41
VENOCO ACQUISITION COMPANY GP, LLC
NOTES TO THE CONSOLIDATED BALANCE SHEET
Note 1. Formation of Company and Basis of Presentation
Venoco Acquisition Company GP, LLC, a Delaware limited liability company (the "General Partner"), was formed on September 25, 2007, to own a 2% general partner interest in Venoco Acquisition Company, L.P., a Delaware limited partnership (the "Partnership"). Venoco, Inc. ("Venoco"), a publicly traded Delaware Corporation owns 100% of the membership interest in the General Partner.
On February 8, 2008, Venoco contributed $1,000 to the General Partner. Subsequently on February 8, 2008, the General Partner contributed $20 to the Partnership in exchange for its 2% general partner interest in the Partnership, which will acquire, exploit, and develop oil and natural gas properties and acquire, own, and operate related assets. The General Partner does not have any business other than holding its 2% general partner interest in the Partnership.
There were no other transactions involving the General Partner through February 8, 2008.
Note 2. Principles of Consolidation
The General Partner's consolidated balance sheet includes the accounts of the Partnership, its only wholly owned subsidiary. The General Partner does not own an interest in any other companies. All material intercompany balances and transactions are eliminated.
F-42
Report of Independent Registered Public Accounting Firm
To the Board of Directors of Venoco, Inc.:
We have audited the accompanying statements of revenues and direct operating expenses for the Hastings Complex for the year ended December 31, 2005 and the three months ended March 31, 2006. These statements are the responsibility of the Venoco, Inc. management. Our responsibility is to express an opinion on these Statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statements of revenues and direct operating expenses are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the internal control over financial reporting for the Hastings Complex. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
The accompanying statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in note 1. The statements are not intended to be a complete presentation of the Hastings Complex's revenues and expenses.
In our opinion, the statements of revenues and direct operating expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses of the Hastings Complex for the year ended December 31, 2005 and the three months ended March 31, 2006, in conformity with accounting principles generally accepted in the United States of America.
/s/ BDO Seidman LLP
Houston, Texas
February 6, 2008
F-43
HASTINGS COMPLEX
Statements of Revenues and Direct Operating Expenses
Year Ended December 31, 2005 and Three Months Ended March 31, 2006
(In thousands)
| | Year Ended December 31, 2005
| | Three Months Ended March 31, 2006
|
---|
Revenues: | | | | | | |
| Oil sales | | $ | 17,135 | | $ | 4,950 |
| |
| |
|
| | Total revenues | | | 17,135 | | | 4,950 |
| |
| |
|
Direct operating expenses: | | | | | | |
| Oil production | | | 6,702 | | | 1,708 |
| Production taxes | | | 703 | | | 209 |
| |
| |
|
| | Total direct operating expenses | | | 7,405 | | | 1,917 |
| |
| |
|
Excess of revenues over direct operating expenses | | $ | 9,730 | | $ | 3,033 |
| |
| |
|
See accompanying notes to statements of revenues and direct operating expenses.
F-44
HASTINGS COMPLEX
Notes to Statements of Revenues and Direct Operating Expenses
Year Ended December 31, 2005 and Three Months Ended March 31, 2006
(1) Basis of presentation
On March 31, 2006 Venoco, Inc. ("Venoco") acquired 100% of the members' interest in TexCal Energy (LP) LLC ("TexCal" and the "TexCal Acquisition"), an independent exploration and production company with properties in Texas and California, for approximately $456.8 million in cash and related financing costs. The TexCal Acquisition included an interest in the Hastings Complex, a producing oil field located onshore Gulf Coast of Texas. Subsequently, 50% of Venoco's interest in the Hastings Complex was designated to be included in a transfer of producing properties to a Delaware limited partnership (the "Partnership") formed on September 25, 2007 by Venoco and which is expected to pursue an initial public offering of its common units.
TexCal did not prepare separate stand alone historical financial statements for the Hastings Complex in accordance with accounting principles generally accepted in the United States of America. Accordingly, it is not practicable to identify all assets and liabilities, or other indirect operating costs applicable to the Hastings Complex. The accompanying statements of revenues and direct operating expenses were prepared from the historical accounting records of TexCal and Venoco.
Certain indirect expenses as further described in Note 3 were not allocated to the Hastings Complex's historical financial records. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by the Partnership.
These statements of revenues and direct operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission and do not represent a complete set of financial statements reflecting financial position, results of operations, shareholders' equity, and cash flows of the Hastings Complex and are not necessarily indicative of the results of operations for the Hastings Complex going forward.
(2) Significant accounting policies
- (a)
- Principles of Combination and Use of Estimates
The statements of revenues and direct operating expenses are derived from the accounts of TexCal and Venoco. All significant intercompany transactions and balances have been eliminated in preparation of the financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.
Total revenues in the accompanying statements of revenues and direct operating expenses include sales of crude oil only. Oil revenues are recognized based on the amount of oil sold to purchasers when delivery to the purchaser has occurred and title has transferred.
- (c)
- Direct Operating Expenses
Direct operating expenses are recognized when incurred and consist of direct expenses of operating the Hastings Complex. Direct operating expenses include the direct cost of production such as lease operating, gathering, processing, and production and other tax expense.
F-45
(3) Excluded Expenses (Unaudited)
The Hastings Complex represents a fractional interest in a group of properties that were part of TexCal prior to the date of the acquisition by Venoco. Indirect general and administrative expenses, interest, income taxes, and other indirect expenses of TexCal were not allocated to the Hastings Complex and have been excluded from the accompanying statements. In addition, management of Venoco believes such indirect expenses are not indicative of future costs or recoveries, which would be incurred by the Partnership.
Also, depreciation, depletion and amortization has been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not be indicative of those expenses, which would be incurred based on the amounts expected to be allocated to the Hastings Complex in connection with the transfer of the properties to the Partnership.
(4) Supplemental Information for Oil Producing Activities (Unaudited)
Supplemental oil reserve information related to the Hastings Complex is presented in accordance with the requirements of statement of financial accounting standards SFAS No. 69,Disclosures about Oil and Gas Producing Activities (SFAS No. 69).
Because oil reserves are based on many assumptions, all of which may substantially differ from actual results, estimates of reserves and timing of development and production may be significantly different from the actual quantities of oil that are ultimately recovered and the timing of such production. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimates.
Proved oil reserves are estimated and prepared in accordance with Securities and Exchange Commission (SEC) guidelines and are a function of; (i) the quality and quantity of available data, (ii) the interpretation of that data, (iii) the accuracy of various economic assumptions used, and (iv) the judgment of the persons preparing the estimate.
The volumes of proved oil reserves shown are estimates, which, by their nature, are subject to later revision. These proved oil reserves were estimated utilizing all available geological and reservoir data as well as production performance data. These estimates are prepared annually by reserve engineers, and revised either upward or downward, as warranted by additional performance data.
F-46
The following table sets forth estimates of the proved oil reserves and changes therein, for the year ended December 31, 2005 and the three months ended March 31, 2006.
| | Crude Oil, Liquids and Condensate (MBbl)
| |
---|
January 1, 2005 | | 5,415 | |
| Revisions of previous estimates | | 697 | |
| Production | | (312 | ) |
| |
| |
December 31, 2005 | | 5,800 | |
| Production | | (80 | ) |
| |
| |
March 31, 2006 | | 5,720 | |
| |
| |
Proved developed reserves as of: | | | |
| December 31, 2005 | | 5,800 | |
| March 31, 2006 | | 5,720 | |
Estimates of future net cash flows from proved oil reserves were made in accordance with SFAS No. 69. The amounts were prepared by Venoco's engineers and are shown in the following table. Estimated future cash flows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted at a rate of 10%. No deduction has been made for general and administrative expenses, interest expense, depreciation, depletion and amortization or for federal or state income taxes.
The present value of future net cash flows does not purport to be an estimate of the fair market value of the Hastings Complex's proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves, and a discount factor more representative of the time value of money and the risks inherent in producing oil.
F-47
The following table sets forth estimates of the standardized measure of discounted future net cash flows from proved oil reserves as of December 31, 2005 and March 31, 2006.
| | December 31, 2005
| | March 31, 2006
| |
---|
| | (In thousands)
| |
---|
Future cash inflows | | $ | 346,962 | | $ | 373,314 | |
Future production costs | | | (179,348 | ) | | (181,832 | ) |
Future development costs | | | (4,275 | ) | | (4,137 | ) |
| |
| |
| |
Future net cash flows | | | 163,339 | | | 187,345 | |
10% discount for estimating timing of cash flows | | | (94,012 | ) | | (109,936 | ) |
| |
| |
| |
Standardized measure of discounted future net cash flows relating to oil reserves | | $ | 69,327 | | $ | 77,409 | |
| |
| |
| |
The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil reserves for the year ended December 31, 2005 and the three months ended March 31, 2006.
| | Year Ended December 31, 2005
| | Three Months Ended March 31, 2006
| |
---|
| | (In thousands)
| |
---|
Beginning of period | | $ | 42,777 | | $ | 69,327 | |
| Sales of oil produced, net of production costs | | | (9,730 | ) | | (3,033 | ) |
| Net changes in prices and production costs | | | 15,450 | | | 10,520 | |
| Development costs incurred during the period | | | 328 | | | 35 | |
| Change in estimated future development costs | | | (26 | ) | | (42 | ) |
| Revisions of previous quantity estimates | | | 8,589 | | | — | |
| Accretion of discount | | | 4,278 | | | 1,733 | |
| Timing and other | | | 7,661 | | | (1,131 | ) |
| |
| |
| |
End of period | | $ | 69,327 | | $ | 77,409 | |
| |
| |
| |
F-48
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Berry Petroleum Company:
We have audited the accompanying Statements of Revenues and Direct Operating Expenses for the West Montalvo Onshore Operations of Berry Petroleum Company for each of the two years in the period ended December 31, 2006. These Statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these Statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the Statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Statements. We believe that our audits provide a reasonable basis for our opinion.
The accompanying Statements were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission as described in Note 1 and are not intended to be a complete presentation of the Company's revenues and expenses.
In our opinion, the Statements of Revenues and Direct Operating Expenses referred to above present fairly, in all material respects, the revenues and direct operating expenses described in Note 1 of West Montalvo Onshore Operations for each of the two years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America.
PricewaterhouseCoopers LLP
Los Angeles, California
February 13, 2008
F-49
WEST MONTALVO ONSHORE OPERATIONS
Statements of Revenues and Direct Operating Expenses
Years Ended December 31, 2005 and 2006
| | 2005
| | 2006
|
---|
| | In thousands
|
---|
Revenues: | | | | | | |
| Oil and natural gas sales | | $ | 8,502 | | $ | 9,425 |
| |
| |
|
| | Total revenues | | | 8,502 | | | 9,425 |
| |
| |
|
Direct operating expenses: | | | | | | |
| Oil and natural gas production | | | 3,064 | | | 3,908 |
| |
| |
|
| | Total direct operating expenses | | | 3,064 | | | 3,908 |
| |
| |
|
Excess of revenues over direct operating expenses | | $ | 5,438 | | $ | 5,517 |
| |
| |
|
See accompanying notes to Statements of Revenues and Direct Operating Expenses.
F-50
WEST MONTALVO ONSHORE OPERATIONS
Notes to Statements of Revenues and Direct Operating Expenses
Years Ended December 2005 and 2006
(1) Basis of presentation
On May 11, 2007 Venoco, Inc. ("Venoco") acquired 100% of the interest in the West Montalvo oil and natural gas properties of Berry Petroleum Company ("Berry" and the "Berry Acquisition"), for approximately $61.3 million in cash, subject to customary post closing adjustments. The Berry Acquisition included the West Montalvo Onshore and Offshore fields, oil and natural gas producing properties located near Ventura, California. Subsequently, one hundred percent of Venoco's interest in the onshore portion of the Berry Acquisition was designated to be included in a transfer of producing properties to a Delaware limited partnership (the "Partnership") which is being sponsored by Venoco and which is expected to pursue an initial public offering of its common units. This onshore portion of the Berry Acquisition is referred to as the "West Montalvo Onshore Operations."
Berry did not prepare separate stand alone historical financial statements for the West Montalvo Onshore Operations in accordance with accounting principles generally accepted in the United States of America. Accordingly, it is not practicable to identify all assets and liabilities, or other indirect operating costs applicable to the West Montalvo Onshore Operations. The accompanying statements of revenues and direct operating expenses were prepared from the historical accounting records of Berry Petroleum Company.
Certain indirect expenses as further described in Note 3 were not allocated to the West Montalvo Onshore Operations' historical financial records. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by the Partnership.
These statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting financial position, results of operations, shareholders' equity, and cash flows of the West Montalvo Onshore Operations and are not necessarily indicative of the results of operations for the West Montalvo Onshore Operations going forward.
(2) Significant accounting policies
- (a)
- Principles of Combination and Use of Estimates
The combined statements of revenues and direct operating expenses are derived from the accounts of Berry Petroleum Company. All significant intercompany transactions and balances have been eliminated in the financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.
Total revenues in the accompanying statements of revenues and direct operating expenses include sales of both oil and natural gas. Berry recognizes revenues based on the amount of oil and natural gas sold to purchasers when delivery to the purchaser has occurred and title has transferred.
Berry uses the entitlement method of accounting for natural gas revenue. There were no significant imbalances with other revenue interest owners during any of the periods presented in these statements.
F-51
- (c)
- Direct Operating Expenses
Direct operating expenses are recognized when incurred and consist of direct expenses of operating the West Montalvo Onshore Operations. Direct operating expenses include the direct cost of production such as lease operating, gathering, processing, and production and other tax expense. Lease operating expenses include lifting costs, well maintenance and repair expenses, surface repair expenses, well workover costs, and other field expenses. Production expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and natural gas production activities.
(3) Excluded Expenses (Unaudited)
The West Montalvo Onshore Operations represent a fractional interest in a group of properties that were part of Berry prior to the date of the acquisition by Venoco. Indirect general and administrative expenses, interest, income taxes, and other indirect expenses of Berry were not allocated to the West Montalvo Onshore Operations and have been excluded from the accompanying statements. In addition, management of Berry believes such indirect expenses are not indicative of future costs or recoveries, which would be incurred by the Partnership.
Also, depreciation, depletion and amortization have been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not be indicative of those expenses expected to be incurred by the Partnership.
(4) Supplemental Information for Oil and Gas Producing Activities (Unaudited)
Supplemental oil and natural gas reserve information related to the West Montalvo Onshore Operations is presented in accordance with the requirements of statement of financial accounting standards No. 69, Disclosures about Oil and Gas Producing Activities (SFAS No. 69).
Because oil and natural gas reserves are based on many assumptions, all of which may substantially differ from actual results, estimates of reserves and timing of development and production may be significantly different from the actual quantities of oil and natural gas that are ultimately recovered and the timing of such production. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimates,
Proved oil and natural gas reserves are estimated and prepared in accordance with Securities and Exchange Commission (SEC) guidelines and are a function of; (i) the quality and quantity of available data, (ii) the interpretation of that data, (iii) the accuracy of various economic assumptions used, and (iv) the judgment of the persons preparing the estimate.
The volumes of proved oil and natural gas reserves shown are estimates, which, by their nature, are subject to later revision. These proved oil and natural gas reserves were estimated utilizing all available geological and reservoir data as well as production performance data. These estimates are prepared annually by reserve engineers, and revised either upward or downward, as warranted by additional performance data.
F-52
The following table sets forth estimates of the proved oil and natural gas reserves (net of royalty interests) and changes therein, for the years ended December 31, 2005 and 2006.
| | Natural Gas MMcf
| | Oil MBbl
| | Total MBoe(1)
| |
---|
January 1, 2005 | | 1,947 | | 3,913 | | 4,238 | |
| Revisions of previous estimates | | 330 | | 132 | | 187 | |
| Production | | (136 | ) | (172 | ) | (195 | ) |
| |
| |
| |
| |
December 31, 2005 | | 2,141 | | 3,873 | | 4,230 | |
| Revisions of previous estimates | | 352 | | 402 | | 461 | |
| Production | | (113 | ) | (155 | ) | (174 | ) |
| |
| |
| |
| |
December 31, 2006 | | 2,380 | | 4,120 | | 4,517 | |
| |
| |
| |
| |
Proved developed reserves as of: | | | | | | | |
| December 31, 2005 | | 989 | | 1,627 | | 1,792 | |
| December 31, 2006 | | 1,228 | | 1,873 | | 2,078 | |
Proved undeveloped reserves as of: | | | | | | | |
| December 31, 2005 | | 1,152 | | 2,246 | | 2,438 | |
| December 31, 2006 | | 1,152 | | 2,247 | | 2,439 | |
- (l)
- Total volumes are in thousands of barrels of oil equivalent (MBoe). For this computation, one barrel is the equivalent of six thousand cubic feet of natural gas.
Estimates of future net cash flows from proved reserves of oil and natural gas were made in accordance with SFAS No. 69. The amounts were prepared by Berry's engineers and are shown in the following table. Estimated future cash flows are reduced by estimated future development, production, abandonment and dismantlement costs based on year-end cost levels, assuming continuation of existing economic conditions. Year end prices were used in the computation of future cash flows. Year end oil prices were $49.53 per barrel and $49.39 per barrel for 2006 and 2005, respectively and year end natural gas prices were $5.96 per Mcf and $8.21 per Mcf for the years 2006 and 2005, respectively. The historical operations of the onshore Montalvo properties were included in Berry's income tax return. However, the standardized measure of discounted future net cash flows does not include income tax.
The present value of future net cash flows does not purport to be an estimate of the fair market value of the West Montalvo Onshore Operations' proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves, and a discount factor more representative of the time value of money and the risks inherent in producing oil and natural gas.
F-53
The following table sets forth estimates of the standardized measure of discounted future net cash flows from proved reserves of oil and natural gas (excluding income taxes) for the years ended December 31, 2005 and 2006.
| | 2005
| | 2006
| |
---|
| | In thousands
| |
---|
Future cash inflows | | $ | 209,035 | | $ | 218,894 | |
Future production costs | | | (63,658 | ) | | (69,255 | ) |
Future development costs | | | (22,283 | ) | | (21,697 | ) |
| |
| |
| |
Future net cash flows | | | 123,094 | | | 127,942 | |
10% discount for estimating timing of cash flows | | | (62,966 | ) | | (64,590 | ) |
| |
| |
| |
Standardized measure of discounted future net cash flows relating to oil and natural gas reserves (excluding income taxes) | | $ | 60,128 | | $ | 63,352 | |
| |
| |
| |
The following table sets forth the changes in standardized measure of discounted future net cash flows (excluding income taxes) relating to proved oil and natural gas reserves for the years ended December 31, 2005 and 2006.
| | 2005
| | 2006
| |
---|
| | In thousands
| |
---|
Beginning of year | | $ | 28,726 | | $ | 60,128 | |
| Sales of oil and natural gas produced, net of production costs | | | (5,439 | ) | | (5,517 | ) |
| Net changes in prices and production costs | | | 33,933 | | | (1,667 | ) |
| Development costs incurred during the period | | | 581 | | | 1,314 | |
| Change in estimated future development costs | | | (3,283 | ) | | (496 | ) |
| Accretion of discount | | | 2,872 | | | 6,013 | |
| Revisions of previous estimates | | | 3,356 | | | 7,968 | |
| Timing and other | | | (618 | ) | | (4,391 | ) |
| |
| |
| |
End of year | | $ | 60,128 | | $ | 63,352 | |
| |
| |
| |
F-54
WEST MONTALVO ONSHORE OPERATIONS
Statements of Revenues and Direct Operating Expenses
Three Months Ended March 31, 2006 and 2007
(Unaudited)
| | Three Months Ended March 31,
|
---|
| | 2006
| | 2007
|
---|
| | In thousands
|
---|
Revenues: | | | | | | |
| Oil and natural gas sales | | $ | 2,206 | | $ | 2,445 |
| |
| |
|
| | Total revenues | | | 2,206 | | | 2,445 |
| |
| |
|
Direct operating expenses: | | | | | | |
| Oil and natural gas production | | | 611 | | | 1,008 |
| |
| |
|
| | Total direct operating expenses | | | 611 | | | 1,008 |
| |
| |
|
Excess of revenues over direct operating expenses | | $ | 1,595 | | $ | 1,437 |
| |
| |
|
See accompanying notes to unaudited Statements of Revenues and Direct Operating Expenses.
F-55
WEST MONTALVO ONSHORE OPERATIONS
Notes to Unaudited Statements of Revenues and Direct Operating Expenses
Three Months Ended March 31, 2006 and 2007
(1) Basis of presentation
On May 11, 2007 Venoco, Inc. ("Venoco") acquired 100% of the interest in the West Montalvo oil and natural gas properties of Berry Petroleum Company ("Berry" and the "Berry Acquisition"), for approximately $61.3 million in cash, subject to customary post closing adjustments. The Berry Acquisition included the West Montalvo Onshore and Offshore fields, oil and natural gas producing properties located near Ventura, California. Subsequently, one hundred percent of Venoco's interest in the onshore portion of the Berry Acquisition was designated to be included in a transfer of producing properties to a Delaware limited partnership (the "Partnership") which is being sponsored by Venoco and which is expected to pursue an initial public offering of its common units. This onshore portion of the Berry Acquisition is referred to as the "West Montalvo Onshore Operations".
Berry did not prepare separate stand alone historical financial statements for the West Montalvo Onshore Operations in accordance with accounting principles generally accepted in the United States of America. Accordingly, it is not practicable to identify all assets and liabilities, or other indirect operating costs applicable to the West Montalvo Onshore Operations. The accompanying statements of revenues and direct operating expenses were prepared from the historical accounting records of Berry Petroleum Company.
Certain indirect expenses as further described in Note 3 were not allocated to the West Montalvo Onshore Operations' historical financial records. Any attempt to allocate these expenses would require significant and judgmental allocations, which would be arbitrary and would not be indicative of the performance of the properties had they been owned by the Partnership.
These statements of revenues and direct operating expenses do not represent a complete set of financial statements reflecting financial position, results of operations, shareholders' equity, and cash flows of the West Montalvo Onshore Operations and are not necessarily indicative of the results of operations for the West Montalvo Onshore Operations going forward.
(2) Significant accounting policies
- (a)
- Principles of Combination and Use of Estimates
The combined statements of revenues and direct operating expenses are derived from the accounts of Berry Petroleum Company. All significant intercompany transactions and balances have been eliminated in the financial statements. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the statements of revenues and direct operating expenses. Actual results could be different from those estimates.
Total revenues in the accompanying statements of revenues and direct operating expenses include sales of both oil and natural gas. Berry recognizes revenues based on the amount of oil and natural gas sold to purchasers when delivery to the purchaser has occurred and title has transferred.
Berry uses the entitlement method of accounting for natural gas revenue. There were no significant imbalances with other revenue interest owners during any of the periods presented in these statements.
F-56
- (c)
- Direct Operating Expenses
Direct operating expenses are recognized when incurred and consist of direct expenses of operating the West Montalvo Onshore Operations. Direct operating expenses include the direct cost of production such as lease operating, gathering, processing, and production and other tax expense. Lease operating expenses include lifting costs, well maintenance and repair expenses, surface repair expenses, well workover costs, and other field expenses. Production expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and natural gas production activities.
(3) Excluded Expenses
The West Montalvo Onshore Operations represent a fractional interest in a group of properties that were part of Berry prior to the date of the acquisition by Venoco. Indirect general and administrative expenses, interest, income taxes, and other indirect expenses of Berry were not allocated to the West Montalvo Onshore Operations and have been excluded from the accompanying statements. In addition, management of Berry believes such indirect expenses are not indicative of future costs or recoveries, which would be incurred by the Partnership.
Also, depreciation, depletion and amortization have been excluded from the accompanying statements of revenues and direct operating expenses as such amounts would not be indicative of those expenses expected to be incurred by the Partnership.
F-57
Appendix A
First Amended and Restated
Agreement of Limited Partnership
of
Venoco Acquisition Company, L.P.
[To be filed by amendment]
A-1
Appendix B
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations, definitions of terms and conventions related to the oil and natural gas industry that are used in this prospectus:
Acquisitions means acquisitions, mergers or exercises of preferential rights of purchase.
Adjusted EBITDA means net income before (i) net interest expense, (ii) loss on extinguishment of debt, (iii) income tax provision, (iv) depreciation, depletion and amortization, (v) amortization of derivative premiums, (vi) pre-tax unrealized gains and losses on derivative instruments, (vii) non-cash expenses relating to share-based payments under FAS 123R and (viii) accretion of abandonment liability.
Adjusted operating surplus generally means, for any period, operating surplus generated with respect to that period, adjusted to:
(a) decrease operating surplus by:
(1) any net increase in working capital borrowings with respect to that period; and
(2) any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; and
(b) increase operating surplus by:
(1) any net decrease in working capital borrowings with respect to that period; and
(2) any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.
Adjusted operating surplus does not include that portion of operating surplus included in clause (1) of the definition of operating surplus.
Available cash means, for any quarter ending prior to liquidation:
(a) the sum of:
(1) all cash and cash equivalents of Venoco Acquisition Company, L.P. and its subsidiaries on hand at the end of that quarter; and
(2) if our general partner so determines, all or a portion of any additional cash or cash equivalents of Venoco Acquisition Company, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter, including cash from working capital borrowings;
(b) less the amount of any cash reserves established by the board of directors of our general partner to:
(1) provide for the proper conduct of the business of Venoco Acquisition Company, L.P. and its subsidiaries (including amounts for maintenance and expansion capital expenditures, future debt service requirements and our anticipated credit needs);
(2) comply with applicable law, any of our debt instruments or other agreements; or
(3) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.
B-1
Bbl means one stock tank barrel or 42 U.S. gallons liquid volume. Bbl is also used to refer to multiple barrels of oil or other liquid hydrocarbons.
Bbl/d means Bbl per day.
Bcf means one billion cubic feet.
Boe means one barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil.
Boe/d means Boe per day.
Btu means one British thermal unit, which is a measure of the amount of heat energy required to raise the temperature of a one-pound mass of water one degree Fahrenheit.
Capital surplus means all available cash distributed by us from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus as of the most recent date of determination of available cash. Any excess available cash will be deemed to be capital surplus.
Common unit arrearage means the amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.
Developed acreage means the number of acres that are allocated or assignable to productive wells or wells capable of production.
Development well means a well drilled within the proved area of an oil or natural gas reservoir to the depth of the stratigraphic horizon known to be productive.
Dry hole or well means an exploration well that is determined not to have discovered proved reserves or a development well found to be incapable of producing hydrocarbons in sufficient quantities such that the estimated proceeds from the sale of future oil and natural gas production would exceed associated production expenses and taxes.
Eligible Holder means, for purposes of this offering, a holder that is both (1) a person or entity qualified to hold an interest in oil and natural gas leases on federal lands and (2) an individual or entity subject to U.S. federal income taxation on our income or an entity not subject to such taxation as long as all of the entity's owners are subject to such taxation.
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 the investors who may own our common units. For this purpose, 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: (1) a citizen of the United States; (2) a corporation organized under the laws of the United States or of any state thereof; (3) a public body, including a municipality; or (4) an association of U.S. 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 U.S. state. Onshore mineral leases or any direct or indirect interest in those leases 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 U.S. state.
In order to comply with certain FERC requirements applicable to entities that pass their taxable income through to their owners, we have adopted certain additional requirements regarding those investors who may own our common and subordinated units. For this purpose, Eligible Holders are
B-2
individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity's owners are subject to such taxation.
Estimated production decline rate means the percentage decrease in annual production from the proved developed producing reserves of the Partnership Properties in 2009 when compared to 2008 as estimated in our Reserve Reports.
Exploitation means a drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Field means an area of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
GAAP means accounting principles that are generally accepted in the United States of America.
Gross acres or wells mean the total acres or wells, as the case may be, in which a working interest is owned.
Interim capital transactions generally means the following transactions if they occur prior to liquidation:
(a) borrowings that are not working capital borrowings;
(b) sales of our equity and debt securities;
(c) sales or other dispositions of assets for cash, other than sales of oil and natural gas production, dispositions of assets made in connection with plugging and abandoning wells and site restoration, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets;
(d) the termination of interest rate hedge contracts or commodity hedge contracts prior to the termination date specified therein;
(e) capital contributions received; and
(f) corporate reorganizations or restructurings.
MBbl means one thousand Bbl.
MBoe means one thousand Boe.
Mcf means one thousand cubic feet and is a measure of natural gas volume.
Mcf/d means Mcf per day.
MMBbl means one million Bbl.
MMBoe means one million Boe.
MMBtu means one million Btu.
MMcf means one million cubic feet.
MMcf/d means MMcf per day.
Net acres or wells mean the net acres or wells, as the case may be, in which a working interest is owned, determined by multiplying gross acres or wells by the working interest that we own in such acres or wells represented by the underlying properties.
NYMEX means the New York Mercantile Exchange.
B-3
NYSE means the New York Stock Exchange.
Oil means crude oil, condensate and natural gas liquids.
Operating expenditures generally means all of our expenditures, including lease operating expenses, taxes, reimbursements of expenses to our general partner, payments made in the ordinary course of business under interest rate and commodity hedging arrangements, estimated maintenance capital expenditures, repayment of working capital borrowings and debt service payments. Operating expenditures will not include:
- (1)
- actual repayment of working capital borrowings deducted from operating surplus that were deemed to have been repaid at the end of the twelve-month period following the borrowing;
- (2)
- payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;
- (3)
- actual maintenance capital expenditures;
- (4)
- expansion capital expenditures;
- (5)
- payment of transaction expenses relating to interim capital transactions; or
- (6)
- distributions to partners.
Operating surplus generally means:
- (1)
- $20.0 million;plus
- (2)
- all of our cash receipts after the closing of this offering, excluding cash from (i) borrowings that are not working capital borrowings, (ii) sales of our equity and debt securities, (iii) sales or other dispositions of assets for cash, other than sales of oil and natural gas production, dispositions of assets made in connection with plugging and abandoning wells and site reclamation, sales of inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets, (iv) the termination of commodity hedge contracts and interest rate swap agreements prior to their respective termination, (v) capital contributions and (vi) corporate reorganizations or restructurings;plus
- (3)
- working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter;plus
- (4)
- cash distributions paid on equity issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or proved reserves) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset is placed into service or the date that it is abandoned or disposed of;less
- (5)
- our operating expenditures after the closing of this offering;less
- (6)
- the amount of cash reserves established by our general partner to provide funds for future operating and capital expenditures;less
- (7)
- all working capital borrowings not repaid within twelve months after having been incurred.
Productive well means 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 means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional natural gas and oil expected to be
B-4
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 developed non-producing reserves means proved oil and natural gas reserves that are developed behind pipe, shut-in or can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
Proved reserves means the estimated quantities of oil, natural gas and natural gas liquids 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 upon future conditions.
(a) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by natural gas-oil and/or oil-water contacts, if any; and (2) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
(b) Reserves that can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
(c) Estimates of proved reserves do not include the following: (1) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (2) oil, natural gas and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (3) oil, natural gas and natural gas liquids, that may occur in undrilled prospects; and (4) oil, natural gas and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved undeveloped reserves means 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 can be 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 means the completion for production of an existing wellbore in another formation from that which the well has been previously completed.
B-5
Reserve Reports means our internal reserve reports based on evaluations prepared by our internal reserve engineers, which were derived from the external reserve reports prepared by our independent reserve engineers that contain our oil and natural gas reserve information as of December 31, 2006.
Reserve-to-production ratio means the amount obtained by dividing estimated proved reserves as of December 31, 2006 by the annualized pro forma average daily net production for the six months ended June 30, 2007.
Reservoir means a porous and permeable underground formation containing a natural accumulation of producible oil or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
SEC means the United States Securities and Exchange Commission.
Standardized measure means the after-tax present value of estimated future net revenues of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs in effect at the specified date and a 10 percent discount rate.
Subordination period. The subordination period will extend until the first day of any quarter beginning after March 31, 2011 that each of the following tests are met:
- (1)
- distributions of available cash from operating surplus on each of the outstanding common units, subordinated units and the 2% general partner interest equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;
- (2)
- the "adjusted operating surplus" generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the minimum quarterly distributions on all of the outstanding common and subordinated units and the 2% general partner interest during those periods on a fully diluted basis during those periods; and
- (3)
- there are no arrearages in payment of the minimum quarterly distribution on the common units.
The subordination period will also end, and each subordinated unit will immediately convert into one common unit, if the unitholders remove our general partner other than for cause and units held by the general partner and its affiliates are not voted in favor of such removal. In those circumstances, any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished and the general partner will have the right to convert its 2% general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.
Undeveloped acreage means lease acreage on which wells have not been drilled or completed to a point that would permit production of commercial quantities of oil or natural gas regardless of whether such acreage contains proved reserves.
U.S.means the United States of America.
Venoco Acquisition Company orthe Partnership means Venoco Acquisition Company, L.P. and its subsidiaries.
Volumetric production payment orVPP means a non-operating interest (the same classification as royalties, overriding royalties and other forms of production payments) in oil and natural gas to be produced from particular properties; it is a non-cost bearing interest (the owner of the VPP does not bear or pay the costs of exploration, development or production); and it has a limited term (it terminates after specific quantities, as adjusted, have been received).
B-6
Working interest means the operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production. With respect to information on the working interest in wells, drilling locations and acreage,"net" wells, drilling locations and acres are determined by multiplying"gross" wells, drilling locations and acres by the entities' working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.
Workover means operations on a producing well to restore or increase production.
B-7

9,100,000 Common Units
Representing Limited Partner Interests
PROSPECTUS
, 2008
Joint Book-Running Managers
LEHMAN BROTHERS
CITI
UBS INVESTMENT BANK
PART II
INFORMATION NOT REQUIRED IN THE PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution.
Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the NYSE listing fee, the amounts set forth below are estimates.
SEC registration fee | | $ | 8,226 |
FINRA filing fee* | | | * |
NYSE listing fee* | | | * |
Printing and engraving expenses* | | | * |
Accounting fees and expenses* | | | * |
Legal fees and expenses* | | | * |
Transfer agent and registrar fees* | | | * |
Miscellaneous* | | | * |
| |
|
| Total | | $ | * |
| |
|
- *
- To be supplied by amendment
We intend to pay all expenses of registration, issuance and distribution of our common units.
Item 14. Indemnification of Directors and Officers.
The section of the prospectus entitled "The Partnership Agreement—Indemnification," incorporated herein by this reference, discloses that we will generally indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events: our general partner; our general partner's general partner; any departing general partner; any person who is or was an affiliate of or owner of an equity interest in a general partner or any departing general partner; any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding four clauses; any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner or any departing general partner; and any person designated by our general partner.
Reference is also made to Section of the Underwriting Agreement to be filed as an exhibit to this registration statement in which we will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, and to contribute to payments that may be required to be made in respect of these liabilities. Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever.
We are authorized to purchase (or to reimburse our general partner for the costs of) insurance against liabilities asserted against and expenses incurred by our general partner, its affiliates and such other persons as the general partner may determine and described in the paragraph above in connection with its activities, whether or not our general partner would have the power to indemnify such person against such liabilities under the provisions described in the paragraphs above. Our general partner has purchased insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.
II-1
Item 15. Recent Sales of Unregistered Securities.
On September 25, 2007, in connection with the formation of Venoco Acquisition Company, L.P., we issued (i) the 2.0% general partner interest in us to Venoco Acquisition Company GP, LLC for $20.00 and (ii) the 98.0% limited partner interest in us to Venoco, Inc. for $980.00. Each issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.
Item 16. Exhibits and Financial Statement Schedules.
- (a)
- The following documents are filed as exhibits to this registration statement:
Exhibit Number
| |
| | Description
|
---|
1.1* | | — | | Form of Underwriting Agreement |
3.1 | | — | | Certificate of Limited Partnership of Venoco Acquisition Company, L.P. |
3.2 | | — | | Certificate of Amendment to Certificate of Limited Partnership of Venoco Acquisition Company, L.P. |
3.3* | | — | | Form of Amended and Restated Limited Partnership Agreement of Venoco Acquisition Company, L.P. (included as Appendix A to the prospectus) |
4.1* | | — | | Specimen Unit Certificate (included as Exhibit A to the Amended and Restated Agreement of Limited Partnership of Venoco Acquisition Company, L.P., which is included as Appendix A to the prospectus) |
5.1* | | — | | Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered |
8.1* | | — | | Opinion of Vinson & Elkins L.L.P. relating to tax matters |
10.1* | | — | | Form of Credit Facility |
10.2* | | — | | Form of Venoco Acquisition Company, L.P. Long-Term Incentive Plan |
10.3* | | — | | Form of Contribution, Conveyance and Assumption Agreement |
10.4* | | — | | Form of Administrative Services Agreement |
10.5* | | — | | Form of Omnibus Agreement |
10.6* | | — | | Form of Tax Sharing Agreement |
21.1* | | — | | List of Subsidiaries of Venoco Acquisition Company, L.P. |
23.1 | | — | | Consent of Deloitte & Touche LLP |
23.2 | | — | | Consent of BDO Seidman, LLP |
23.3 | | — | | Consent of PricewaterhouseCoopers LLP |
23.4* | | — | | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1) |
23.5* | | — | | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1) |
24.1 | | — | | Powers of Attorney (included on the signature page) |
99.1 | | — | | Consent of Nominee for Director |
99.2 | | — | | Consent of Nominee for Director |
- *
- To be filed by amendment.
II-2
Item 17. Undertakings.
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
The registrant undertakes to send to each limited partner at least on an annual basis a detailed statement of any transactions with Venoco Acquisition Company GP, LLC or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to Venoco Acquisition Company GP, LLC or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.
The registrant undertakes to provide to the limited partners the financial statements required by Form 10-K for the first full fiscal year of operations of the partnership.
II-3
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver, State of Colorado, on February 13, 2008.
| | VENOCO ACQUISITION COMPANY, L.P. |
| | By: | | VENOCO ACQUISITION COMPANY GP, LLC, its General Partner |
| | By: | | /s/ TIMOTHY MARQUEZ Timothy Marquez Chief Executive Officer |
Each person whose signature appears below appoints Timothy Marquez, William Schneider and Timothy Ficker, and each of them, any of whom may act without the joinder of the other, as such person's true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for such person and in such person's name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this registration statement and any registration statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933 and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his or her substitute and substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed below by the following persons in the capacities indicated on February 13, 2008.
Signature
| | Title
|
---|
| | |
/s/ TIMOTHY MARQUEZ Timothy Marquez | | Chairman of the Board and Chief Executive Officer (Principal Executive Officer) |
/s/ WILLIAM SCHNEIDER William Schneider | | President |
/s/ TIMOTHY FICKER Timothy Ficker | | Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer) |
II-4
EXHIBIT INDEX
Exhibit Number
| |
| | Description
|
---|
1.1* | | — | | Form of Underwriting Agreement |
3.1 | | — | | Certificate of Limited Partnership of Venoco Acquisition Company, L.P. |
3.2 | | — | | Certificate of Amendment to Certificate of Limited Partnership of Venoco Acquisition Company, L.P. |
3.3* | | — | | Form of Amended and Restated Limited Partnership Agreement of Venoco Acquisition Company, L.P. (included as Appendix A to the prospectus) |
4.1* | | — | | Specimen Unit Certificate (included as Exhibit A to the Amended and Restated Agreement of Limited Partnership of Venoco Acquisition Company, L.P., which is included as Appendix A to the prospectus) |
5.1* | | — | | Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered |
8.1* | | — | | Opinion of Vinson & Elkins L.L.P. relating to tax matters |
10.1* | | — | | Form of Credit Facility |
10.2* | | — | | Form of Venoco Acquisition Company, L.P. Long-Term Incentive Plan |
10.3* | | — | | Form of Contribution, Conveyance and Assumption Agreement |
10.4* | | — | | Form of Administrative Services Agreement |
10.5* | | — | | Form of Omnibus Agreement |
10.6* | | — | | Form of Tax Sharing Agreement |
21.1* | | — | | List of Subsidiaries of Venoco Acquisition Company, L.P. |
23.1 | | — | | Consent of Deloitte & Touche LLP |
23.2 | | — | | Consent of BDO Seidman, LLP |
23.3 | | — | | Consent of PricewaterhouseCoopers LLP |
23.4* | | — | | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1) |
23.5* | | — | | Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1) |
24.1 | | — | | Powers of Attorney (included on the signature page) |
99.1 | | — | | Consent of Nominee for Director |
99.2 | | — | | Consent of Nominee for Director |
- *
- To be filed by amendment.