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EX-23.1 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - Pacific Coast Oil Trustd273119dex231.htm
EX-23.2 - CONSENT OF PRICEWATERHOUSECOOPERS LLP - Pacific Coast Oil Trustd273119dex232.htm
EX-23.5 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC - Pacific Coast Oil Trustd273119dex235.htm
EX-3.2 - AMENDMENT TO CERTIFICATE OF LIMITED PARTNERSHIP OF PACIFIC COAST ENERGY CO LP - Pacific Coast Oil Trustd273119dex32.htm
EX-3.1 - CERTIFICATE OF LIMITED PARTNERSHIP OF PACIFIC COAST ENERGY COMPANY LP - Pacific Coast Oil Trustd273119dex31.htm
EX-3.4 - CERTIFICATE OF TRUST - Pacific Coast Oil Trustd273119dex34.htm
EX-3.5 - TRUST AGREEMENT - Pacific Coast Oil Trustd273119dex35.htm
Table of Contents

As filed with the Securities and Exchange Commission on January 6, 2012

Registration No. 333-            

 

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

Pacific Coast Oil Trust   Pacific Coast Energy Company LP
(Exact Name of co-registrant as specified in its charter)   (Exact Name of co-registrant as specified in its charter)
Delaware   Delaware
(State or other jurisdiction of incorporation or organization)   (State or other jurisdiction of incorporation or organization)
1311   1311
(Primary Standard Industrial Classification Code Number)   (Primary Standard Industrial Classification Code Number)
80-6216242   20-1241171
(I.R.S. Employer Identification No.)   (I.R.S. Employer Identification No.)

919 Congress Avenue, Suite 500

Austin, Texas 78701

(512) 236-6599

 

515 South Flower Street, Suite 4800

Los Angeles, California 90071

(213) 225-5900

Attention: Gregory C. Brown

(Address, including zip code, and

telephone number, including

area code, of co-registrant’s Principal Executive Offices)

 

(Address, including zip code, and

telephone number, including

area code, of co-registrant’s Principal Executive Offices)

The Bank of New York Mellon Trust

Company, N.A., Trustee

919 Congress Avenue, Suite 500

Austin, Texas 78701

(512) 236-6599

Attention: Michael J. Ulrich

(Name, address, including zip code, and

telephone number,

including area code, of agent for service)

 

Gregory C. Brown

515 South Flower Street, Suite 4800

Los Angeles, California

90071

(213) 225-5900

(Name, address, including zip code, and

telephone number,

including area code, of agent for service)

Copies to:

 

Sean T. Wheeler

Steven B. Stokdyk

Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

(713) 546-5400

 

Gerald M. Spedale

Baker Botts L.L.P

910 Louisiana, Suite 3200

Houston, Texas 77002

(713) 229-1234

 

 

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.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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.  ¨

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.  ¨

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

 

Large accelerated filer  ¨      Accelerated filer  ¨            Non-accelerated filer  þ   Smaller reporting company  ¨   
          (Do not check if a smaller reporting company)     

 

 

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities to be Registered

   Proposed Maximum Aggregate
Offering Price(1)(2)
  

Amount of
Registration

Fee

Units of Beneficial Interest in Pacific Coast Oil Trust

   $345,000,000    $39,537

 

 

(1) Includes trust units issuable upon exercise of the underwriters’ option to purchase additional trust units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

The co-registrants hereby amend this Registration Statement on such date or dates as may be necessary to delay its effective date until the co-registrants 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.

 

 

 


Table of Contents

The information in this 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 prospectus is not an offer to sell these in any state where the offer or sale is not permitted.

 

 

Subject to Completion, dated January 6, 2012

PROSPECTUS

 

 

Trust Units

LOGO

 

 

This is the initial public offering of units of beneficial interest in Pacific Coast Oil Trust, or the “trust.” Pacific Coast Energy Company LP, or “PCEC,” has formed the trust and, immediately prior to the closing of this offering, will convey, or cause to be conveyed, net profits interests in oil properties to the trust in exchange for              trust units. PCEC is offering              trust units to be sold in this offering and will receive all of the proceeds derived therefrom. After the offering, PCEC will own              trust units, or              trust units if the underwriters exercise their option to purchase additional trust units from PCEC. No public market currently exists for the trust units. PCEC is a privately held Delaware limited partnership engaged in the production and development of oil and natural gas from properties located onshore in California.

The trust intends to apply to list the trust units on the New York Stock Exchange under the symbol “ROYT.”

PCEC expects that the public offering price will be between $         and $         per trust unit.

The trust units. Trust units are equity securities of the trust and represent undivided beneficial interests in the trust assets. They do not represent any interest in PCEC.

The trust. The trust will own net profits interests in properties held by PCEC in California, which we refer to as the Underlying Properties, as of the date of the conveyances of the net profits interests to the trust. The net profits interests will entitle the trust to receive 80% of the net profits from the sale of oil and natural gas production from proved developed reserves on the Underlying Properties as of September 30, 2011 and 25% of the net profits from the sale of oil and natural gas production from the remaining Underlying Properties. The conveyed interests are referred to as the “Net Profits Interests.”

The trust unitholders. As a trust unitholder, you will receive monthly cash distributions from the proceeds that the trust receives from PCEC pursuant to the Net Profits Interests. The trust’s ability to pay monthly cash distributions will depend on its receipt of net profits attributable to the Net Profits Interests, which net profits will depend on, among other things, volumes produced, wellhead prices, price differentials, production and development costs, potential reductions or suspensions of production, and the amount and timing of trust administrative expenses.

Investing in the trust units involves a high degree of risk. Please read “Risk Factors” beginning on page 16 of this prospectus.

 

     Per Trust Unit      Total  

Price to the public

   $                    $                

Underwriting discounts and commissions(1)

   $         $     

Proceeds to PCEC, before expenses

   $         $     

 

(1) Excludes a structuring fee of     % of the gross proceeds of the offering payable to Barclays Capital Inc. by PCEC for the evaluation, analysis and structuring of the trust.

PCEC has granted the underwriters an option to purchase up to an additional              trust units from it on the same terms and conditions set forth above if the underwriters sell more than              trust 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.

Barclays Capital, on behalf of the underwriters, expects to deliver the trust units on or about                     , 2012.

 

 

 

Barclays Capital

 

 

Prospectus dated                     , 2012


Table of Contents

TABLE OF CONTENTS

 

PROSPECTUS SUMMARY

     1   

RISK FACTORS

     16   

FORWARD-LOOKING STATEMENTS

     31   

USE OF PROCEEDS

     32   

PACIFIC COAST ENERGY COMPANY LP

     33   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     39   

THE TRUST

     40   

PROJECTED CASH DISTRIBUTIONS

     41   

THE UNDERLYING PROPERTIES

     48   

COMPUTATION OF NET PROFITS

     66   

DESCRIPTION OF THE TRUST AGREEMENT

     70   

DESCRIPTION OF THE TRUST UNITS

     75   

TRUST UNITS ELIGIBLE FOR FUTURE SALE

     78   

UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

     80   

STATE TAX CONSIDERATIONS

     87   

ERISA CONSIDERATIONS

     88   

SELLING TRUST UNITHOLDER

     89   

UNDERWRITING

     90   

LEGAL MATTERS

     96   

EXPERTS

     96   

WHERE YOU CAN FIND MORE INFORMATION

     96   

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

     97   

INDEX TO FINANCIAL STATEMENTS OF PACIFIC COAST OIL TRUST

     F-1   

INFORMATION ABOUT PACIFIC COAST ENERGY COMPANY LP

     PCEC -1   

INDEX TO FINANCIAL STATEMENTS OF PACIFIC COAST ENERGY COMPANY LP

     PCEC F-1   

SUMMARY OF RESERVE REPORT OF PACIFIC COAST ENERGY COMPANY LP AS OF SEPTEMBER 30, 2011

     ANNEX A-1   

SUMMARY OF RESERVE REPORT OF PACIFIC COAST ENERGY COMPANY LP AS OF DECEMBER 31, 2010

     ANNEX B-1   

SUMMARY OF RESERVE REPORT OF PACIFIC COAST OIL TRUST AS OF SEPTEMBER 30, 2011

     ANNEX C-1   

Important Notice About Information in This Prospectus

PCEC and the trust have not, and the underwriters have not, authorized anyone to provide you with additional or different information. If anyone provides you with additional, different or inconsistent information, you should not rely on it. This prospectus is not an offer to sell or a solicitation of an offer to buy the trust units in any jurisdiction where such offer and sale would be unlawful. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front of this document. The business, financial condition, results of operations and prospects of PCEC and the trust may have changed since such date.


Table of Contents

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. To understand this offering fully, you should read the entire prospectus carefully, including the risk factors, the summary reserve reports and the financial statements and notes to those statements. Unless otherwise indicated, all information in this prospectus assumes (a) an initial public offering price of $         per trust unit and (b) no exercise of the underwriters’ option to purchase additional trust units.

Unless otherwise indicated, as used in this prospectus, (i) “PCEC” refers to Pacific Coast Energy Company LP and its subsidiaries, including any predecessor entities of PCEC, (ii) the “Underlying Properties” refers to the Orcutt properties located onshore in the Santa Maria Basin and the East Coyote, Sawtelle and West Pico properties located onshore in the Los Angeles Basin held by PCEC and (iii) “proved developed reserves” refers to proved developed producing and proved developed non-producing reserves, as such terms are defined by the Securities and Exchange Commission, or the “SEC.”

References in this prospectus to future production from, or future reserves or revenues attributable to, PCEC’s East Coyote and Sawtelle properties assume that PCEC’s average working interest in such properties increases from approximately 5.0% to approximately 37.6% in April 2012 after certain payout milestones are achieved. We refer to this increase in PCEC’s interest as the East Coyote and Sawtelle Reversion. However, references in this prospectus to historical production, reserves or revenues do not give effect to the East Coyote and Sawtelle Reversion. Please read “Risk Factors—A delay in the East Coyote and Sawtelle Reversion will result in lower distributions to unitholders than those projected, which would continue until the reversion occurs.”

Netherland, Sewell & Associates, Inc., referred to in this prospectus as “Netherland Sewell,” an independent engineering firm, provided the estimates of proved oil and natural gas reserves as of December 31, 2010 and September 30, 2011 included in this prospectus. These estimates are contained in summaries prepared by Netherland Sewell of its reserve reports as of December 31, 2010 and September 30, 2011 for the Underlying Properties held by PCEC and the Net Profits Interests (as defined below) held by the trust. These summaries are located at the back of this prospectus in Annexes A, B and C and are collectively referred to in this prospectus as the “reserve reports.” You will find definitions for terms relating to the oil and natural gas business in “Glossary of Certain Oil and Natural Gas Terms.”

Pacific Coast Oil Trust

Pacific Coast Oil Trust is a Delaware statutory trust formed by PCEC in January 2012 to own net profits interests in the Underlying Properties. The net profits interests, which we refer to as the “Net Profits Interests,” will entitle the trust to receive:

 

   

80% of the net profits from the sale of oil and natural gas production from proved developed reserves on the Underlying Properties as of September 30, 2011, which we refer to as the “Developed Properties”; and

 

   

25% of the net profits from the sale of oil and natural gas production from the remaining Underlying Properties, which we refer to as the “Remaining Properties.”

Net profits payable to the trust will depend on production quantities, sales prices of oil and natural gas and costs to develop and produce the oil and natural gas. If at any time costs should exceed gross proceeds, neither the trust nor the trust unitholders would be liable for the excess costs. However, the trust would not receive any net profits until future net profits exceed the total of those excess costs, plus interest. The trust calculates the net profits from the Underlying Properties separately for the Developed Properties and the Remaining Properties. Any excess costs for either the Developed Properties or the Remaining Properties will not reduce net profits calculated for the other. Please read “Computation of Net Profits.”

 

 

1


Table of Contents

The trust will make monthly cash distributions of all of its monthly cash receipts, after deduction of fees and expenses for the administration of the trust, to holders of its trust units as of the applicable record date (generally the last business day of each calendar month) on or before the 10th business day after the record date. The Net Profits Interests will be entitled to a share of the profits from and after April 1, 2012 attributable to production from the Underlying Properties from and after April 1, 2012. The trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time.

The Underlying Properties are located in California in the Santa Maria and Los Angeles Basins. PCEC operated approximately 98% of the average daily production from the Underlying Properties for the month ended September 30, 2011. The Underlying Properties held approximately 33.3 MMBoe in proved reserves as of September 30, 2011, which were approximately 98% oil and 61% proved developed. The Underlying Properties produced approximately 3,391 Boe/d from 265 producing wells for the month ended September 30, 2011. The following table summarizes certain information regarding the proved reserves and production associated with the Underlying Properties as of and for the periods indicated. The reserve reports were prepared by Netherland Sewell in accordance with criteria established by the SEC. For information regarding proved reserves and production related to the Net Profits Interests, please read “The Underlying Properties.”

 

        Underlying Properties  

Properties

  PCEC Operated   Average Daily
Net Production
for Month
Ended
September 30,
2011 (Boe/d)
    Producing
Wells
    Proved Reserves as of
September 30, 2011(1)
    R/P Ratio as of
September 30,
2011(3)
 
        Total
(MBoe)(2)
    % Oil     % Proved
Developed
Reserves
   

Orcutt, Conventional

  2004 – Present     1,957        123        11,351        100     100     16.0   

West Pico(4)

  1993 – Present     721        39        3,758        85     66     16.2   

Orcutt, Diatomite

  2005 – Present     649        46        15,289        100     24     68.6   

East Coyote

  1999 – Present     23        46        1,636        100     100     200.8   

Sawtelle

  1993 – Present     41        11        1,247        98     100     78.7   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

      3,391        265        33,281        98     61     28.0   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from October 1, 2010 through September 30, 2011, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $94.29 per Bbl and a price for natural gas of $4.16 per MMBtu.
(2) Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas are the energy equivalent of one Bbl of oil.
(3) The R/P ratio, or the reserves-to-production ratio, is a measure of the number of years that a specified reserve base could support a fixed amount of production. This ratio is calculated by dividing total estimated proved reserves of the subject properties at the end of a period by annual total production for the prior twelve months. Because production rates naturally decline over time, the R/P ratio is not a useful estimate of how long properties should economically produce.
(4) The West Pico property consists of the West Pico Unit and includes three wells owned by the Stocker JV (a joint venture between PCEC and Plains Exploration & Production Company, or “PXP”).

Underlying Properties

The Underlying Properties are located onshore in California in the Santa Maria and Los Angeles Basins, both of which are characterized by long producing histories.

 

 

2


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The Santa Maria Basin is one of California’s largest and longest producing oil regions. The Santa Maria Basin has produced over one billion Bbls of oil since its discovery in 1901 and is characterized by oilfields with long production histories. PCEC produces oil and natural gas from its Orcutt properties in the Santa Maria Basin. Currently, a majority of production in the Orcutt oilfield is produced from formations utilizing conventional production methods. Beginning in the 1990s, companies in California began to focus on the development of the Diatomite formations, a typically shallow zone. The Orcutt Diatomite formation lies approximately 100 to 900 feet below the surface and is produced by utilizing cyclic steam injection. PCEC utilizes primarily water flooding to produce oil from its conventional Orcutt properties, and since 2005, has utilized cyclic steam injection to produce oil from the Diatomite formation in its Orcutt properties.

Similar to the Santa Maria Basin, the Los Angeles Basin is characterized by its mature oilfields with long production histories. The Los Angeles Basin has produced more than nine billion Bbls of oil since its discovery in 1892. Within the Los Angeles Basin, PCEC produces oil and natural gas from its conventional West Pico, East Coyote and Sawtelle properties.

The following graph shows estimated average daily production and decline rates of total proved reserves attributable to 80% of proved developed reserves and 25% of proved undeveloped reserves based on the pricing and other assumptions set forth in the reserve report for the Underlying Properties. This graph presents the total proved volumes and decline rates as reflected in the reserve report broken down by two reserve categories (proved developed and proved undeveloped reserves) as of September 30, 2011. This graph does not reflect any probable or possible reserves.

LOGO

 

 

(1) Represents 80% of sales volumes from the proved developed reserves as of September 30, 2011.
(2) Represents 25% of sales volumes from the proved undeveloped reserves as of September 30, 2011.

 

 

3


Table of Contents

Key Investment Considerations

The following are some key investment considerations related to the Underlying Properties, the Net Profits Interests and the trust units:

 

   

Mature, primarily oil asset base with predictable production and long lived reserves. The Underlying Properties consist primarily of oil reserves and prospects in multiple geologic horizons in mature oilfields located onshore in California. As of September 30, 2011, proved reserves were comprised of approximately 98% oil. Long producing histories in the Santa Maria and Los Angeles Basins provide for well established production profiles and increased certainty of production estimates.

 

   

Substantial proved developed oil reserves. Proved developed reserves are generally considered the most valuable and lowest risk category of reserves. As of September 30, 2011, approximately 61% of the volumes of the proved reserves associated with the Underlying Properties and 84% of the volumes of the proved reserves associated with the trust were attributed to proved developed reserves. As of September 30, 2011, the Underlying Properties had a proved reserves to production ratio of 28.0 years and proved developed reserves to production ratio of 17.2 years.

 

   

Significant resource base and original oil in place with considerable development opportunities. PCEC believes that the Underlying Properties are likely to offer economic development opportunities in the future that are not reflected in existing proved reserves and could significantly increase future reserves and production. The fields within the Underlying Properties were estimated to hold approximately 1.6 billion Bbls of original oil in place, or “OOIP.” The Diatomite formation in PCEC’s Orcutt properties offers significant development opportunities for the Underlying Properties. PCEC expects to implement several projects starting in 2012 to increase production from the Underlying Properties. These projects include developing in the near term 38 wells in the Diatomite formation. Further projects may include permitting and drilling additional Diatomite wells in areas not currently developed. In addition to these projects, future increases in estimated oil recovery factors in the Santa Maria and Los Angeles Basins may significantly increase reserves and production. Such increases in recovery factors may occur through, among other means, technological advances, implementation of additional enhanced recovery techniques, infill drilling and production outperformance.

 

   

Significant percentage of operated properties. PCEC owned a majority working interest in, and operated approximately 98% of the average daily production from, the Underlying Properties for the month ended September 30, 2011. This high level of operational control allows PCEC to use its technical and operational expertise to manage overhead, production and drilling costs and capital expenditures and to control the timing and amount of discretionary expenditures for exploration, exploitation and development activities. PCEC is not under any obligation to drill in order to hold leases since 100% of the properties are already held by production or owned in fee. In addition, PCEC’s management team has managed the operations of the Underlying Properties for an average of twelve years.

 

   

High operating margins provide strong cash flow profile. The Underlying Properties have historically generated substantial operating margins. Lease operating expenses and property and other taxes related to the Underlying Properties averaged $33.06 per Boe for the nine months ended September 30, 2011. During the same period, the averaged realized sales price for oil and natural gas (excluding the effects of hedges) averaged $87.51 per Boe, providing an operating margin of $54.45 per Boe, or 62%.

 

   

Initial downside crude oil price protection with long-term direct exposure to oil prices. To mitigate the negative effects of a possible decline in oil prices on distributable income to the trust, PCEC intends to enter into commodity derivative contracts with respect to 50% to 70% of expected oil production for 2012 and 2013 from the proved developed reserves attributable to the Underlying Properties in the reserve report. These commodity derivative contracts may include a combination of puts, swaps, and collars to mitigate the risk of price declines to the trust, while still allowing the trust to benefit from increases in oil prices.

 

 

4


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Alignment of interests between PCEC and the trust unitholders. Immediately following the closing of this offering, PCEC will have an effective ownership of approximately     % of the net profits attributable to the sale of oil and natural gas produced from the Underlying Properties, including its retained 20% net profits interest in the Developed Properties, its retained 75% net profits interest in the Remaining Properties and its ownership of approximately     % of the trust units. By having a material, direct economic interest in the Underlying Properties, PCEC is incentivized to deploy capital on projects where it is likely to successfully increase production or reserves at attractive returns. PCEC expects to maintain a strong financial position, including a borrowing base credit facility, which will allow it and the trust to capitalize on future projects on the Underlying Properties.

Formation Transactions

At or prior to the closing of this offering, the following transactions, which are referred to herein as the “Formation Transactions,” will occur:

 

   

PCEC will convey, or cause to be conveyed, to the trust the Net Profits Interests effective as of April 1, 2012 in exchange for              trust units in the aggregate, representing all of the outstanding trust units of the trust.

 

   

PCEC will sell              trust units offered hereby, representing an     % interest in the trust. PCEC will also make available during the 30-day option period up to              trust units for the underwriters to purchase at the initial offering price to cover over-allotments. PCEC intends to use the proceeds of the offering as disclosed under “Use of Proceeds.”

 

   

PCEC and the trust will enter into an administrative services agreement that will define the services PCEC will provide to the trust on an ongoing basis as well as its compensation. Please read “The Trust.”

Structure of the Trust

The following chart shows the relationship of PCEC, the trust and the public trust unitholders after the closing of this offering.

LOGO

 

 

5


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Risk Factors

An investment in the trust units involves risks associated with fluctuations in commodity prices, the operation of the Underlying Properties, certain regulatory and legal matters, the structure of the trust and the tax characteristics of the trust units. Please read carefully the risks described under “Risk Factors” on page 16 of this prospectus.

 

   

Prices of oil and natural gas fluctuate, and changes in prices could reduce proceeds to the trust and cash distributions to trust unitholders.

 

   

Estimates of future cash distributions to trust unitholders are based on assumptions that are inherently subjective.

 

   

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.

 

   

A delay in the East Coyote and Sawtelle Reversion will result in lower distributions to unitholders than those projected, which would continue until the reversion occurs.

 

   

Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to trust unitholders.

 

   

The trust is passive in nature and neither the trust nor the trust unitholders will have any ability to influence PCEC or control the operations or development of the Underlying Properties.

 

   

Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the trust unitholders.

 

   

The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

 

   

PCEC may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent.

 

   

PCEC may be unable to successfully renegotiate its administrative services agreement with BreitBurn Management LLC, a wholly owned subsidiary of BreitBurn Energy Partners L.P., or “BBEP,” which failure would require PCEC to hire its own management and other employees.

 

   

The reserves attributable to the Underlying Properties are depleting assets and production from those reserves may diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders may decrease over time.

 

   

A change in crude oil price differentials may adversely impact the cash distributions available to trust unitholders.

 

   

The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust.

 

   

The generation of profits for distribution by the trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.

 

 

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ConocoPhillips purchases a significant percentage of PCEC’s production, and a decision by ConocoPhillips to discontinue or reduce its purchases of PCEC’s production may adversely impact the cash distributions available to trust unitholders.

 

   

The trustee must, under certain circumstances, sell the Net Profits Interests and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.

 

   

PCEC may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units.

 

   

There has been no public market for the trust units, and accordingly the value after this offering may differ from the price in the offering.

 

   

The trading price for the trust units may not reflect the value of the Net Profits Interests held by the trust, which would adversely affect the return on an investment in the units.

 

   

Conflicts of interest could arise between PCEC and its affiliates, on the one hand, and the trust and the trust unitholders, on the other hand, which could harm the business or financial results of the trust.

 

   

The trust is managed by a trustee who cannot be replaced except by a majority vote of the trust unitholders at a special meeting, which may make it difficult for trust unitholders to remove or replace the trustee.

 

   

Trust unitholders have limited ability to enforce provisions of the conveyances creating the Net Profits Interests, and PCEC’s liability to the trust is limited.

 

   

Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.

 

   

The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.

 

   

The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders.

 

   

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that PCEC produces while the physical effects of climate change could disrupt their production and cause it to incur significant costs in preparing for or responding to those effects.

 

   

Recent regulatory changes in California have and may continue to negatively impact PCEC’s production in its Diatomite properties.

 

   

The bankruptcy of PCEC or any third party operator could impede the operation of wells and the development of the proved undeveloped reserves.

 

   

Due to the trust’s lack of industry and geographic diversification, adverse developments in California could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders.

 

 

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The receipt of payments by PCEC based on any commodity derivative contract will depend upon the financial position of the commodity derivative contract counterparties. A default by any commodity derivative contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

 

   

The trust has not requested a ruling from the Internal Revenue Service, or the “IRS,” regarding the tax treatment of the trust. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, the trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to trust unitholders.

 

   

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

 

   

You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.

 

   

A portion of any tax gain on the disposition of the trust units could be taxed as ordinary income.

 

   

The trust will allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.

 

   

As a result of investing in trust units, you may become subject to state and local taxes and return filing requirements in California.

Summary Historical, Unaudited and Pro Forma Financial, Operating and Reserve Data of PCEC

The summary historical audited financial data of PCEC as of December 31, 2010 and 2009 and for the two-year period ended December 31, 2010 and the period from August 26, 2008 to December 31, 2008 have been derived from PCEC’s audited financial statements. The summary historical audited financial data for the period from January 1, 2008 to August 25, 2008 has been derived from PCEC’s predecessor’s audited financial statements. The summary historical unaudited interim financial data of PCEC as of September 30, 2011 and 2010 and for the nine-month periods ended September 30, 2011 and 2010 have been derived from PCEC’s unaudited interim financial statements. The unaudited interim financial statements were prepared on a basis consistent with the audited statements and, in the opinion of PCEC’s management, include all adjustments (consisting only of normal recurring adjustments) necessary to state fairly the results of PCEC for the periods presented.

The summary unaudited pro forma financial data as of and for the nine months ended September 30, 2011 and for the year ended December 31, 2010 has been derived from the unaudited pro forma financial statements of PCEC included elsewhere in this prospectus. The pro forma data has been prepared as if the conveyances of the Net Profits Interests and the offer and sale of the trust units and application of the net proceeds therefrom had taken place (i) on September 30, 2011, in the case of the pro forma balance sheet information as of September 30, 2011, and (ii) as of January 1, 2010, in the case of the pro forma statements of earnings for the nine months ended September 30, 2011 and for the year ended December 31, 2010. The summary historical, unaudited and pro forma financial, operating and reserve data presented below should be read in conjunction with “Pacific Coast Energy Company LP—Selected Historical, Unaudited and Pro Forma Financial Data of PCEC,” “Information About Pacific Coast Energy Company LP—Management’s Discussion and Analysis of Financial Condition and Results of Operations of PCEC” and the accompanying financial statements and related notes of PCEC included elsewhere in this prospectus.

 

 

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Summary Historical, Unaudited and Pro Forma Financial Data of PCEC

 

    PCEC Pro Forma for the
Offering (Including the
Conveyances of the
Net Profits Interests)
    PCEC          Predecessor  
    Nine Months
Ended
September 30,
2011
    Year Ended
December 31,
2010
    Nine Months Ended
September 30,
    Year Ended
December 31,
    August 26 to
December 31,
2008
         January 1 to
August 25,
2008
 
      2011     2010     2010     2009        
(In thousands)   (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)                         

Total revenues and other income

  $ 106,370      $ 62,805      $ 114,756      $ 61,737      $ 62,805      $ 6,478      $ 166,934          $ 61,472   

Net income (loss)

  $ 59,677      $ (307   $ 57,012      $ 1,697      $ (18,810   $ (90,980   $ 135,842          $ 25,063   

Total assets (at period end)

  $ 484,047        $ 428,072      $ 406,795      $ 393,315      $ 398,245      $ 509,405          $ 221,675   

Total debt(1) (at period end)

  $        $ 124,000      $ 135,000      $ 142,000      $ 133,000      $ 155,500          $ 13,500   

Partners’ equity (at period end)

  $ 447,953        $ 267,978      $ 244,999      $ 211,445      $ 230,742      $ 322,125          $ 171,726   

 

(1) As of September 30, 2011, PCEC had $94.0 million of borrowings under its senior secured credit agreement that is classified as short-term debt.

Operating and Reserves Data of PCEC

The following table provides the oil and natural gas sales volumes, average sales prices, average costs per Boe and capital expenditures for PCEC for the nine months ended September 30, 2011 and 2010 and for the years ended December 31, 2010, 2009 and 2008 and reserves and production data for PCEC as of September 30, 2011 and December 31, 2010, 2009 and 2008.

 

     Nine Months Ended
September 30,
     Year Ended December 31,  
     2011      2010      2010      2009      Combined 2008  
     (Unaudited)  

Operating Data:

              

Sales volumes:

              

Oil (MBbls)

     869         817         1,086         1,240         947   

Natural gas (MMcf)

     212         207         259         305         315   

Total sales (MBoe)

     905         851         1,129         1,291         999   

Average sales prices:

              

Oil (per Bbl)

   $ 90.14       $ 68.07       $ 69.99       $ 53.22       $ 86.57   

Natural gas (per Mcf)

     3.87         3.70         3.45         2.72         7.22   

Average costs per Boe:

              

Lease operating expenses

   $ 30.89       $ 28.90       $ 29.37       $ 27.02       $ 33.12   

Production and other taxes

     2.17         1.67         2.08         2.92         1.81   

Capital expenditures (in thousands):

              

Property development costs

   $ 20,576       $ 29,992       $ 44,000       $ 15,852       $ 28,291   

Proved reserves (at period end):

              

Proved developed (MBoe)

     20,392            17,462         11,566         6,442   

Proved undeveloped (MBoe)

     12,889            1,847         1,276         440   

Total proved reserves (MBoe)

     33,281            19,309         12,842         6,882   

Production (MBoe)

     905         851         1,129         1,291         999   

 

 

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Unaudited Pro Forma Distributable Income of the Trust

The table below outlines the calculation of pro forma distributable income from the Net Profits Interests for the nine months ended September 30, 2011 and for the year ended December 31, 2010 based on the excess of revenues over direct operating expenses attributable to the Net Profits Interests for the nine months ended September 30, 2011 and for the year ended December 31, 2010 as if the contemplated Formation Transactions had occurred on January 1, 2010. The table below should be read in conjunction with the unaudited pro forma financial information of the trust included elsewhere in this prospectus. The pro forma amounts below do not purport to present distributable income of the trust had the Formation Transactions contemplated actually occurred on January 1, 2010. Distributable income of the trust will be calculated using a modified cash basis of accounting. Please refer to the unaudited pro forma financial information for the trust included elsewhere in this prospectus for more information. As a result, you should view the amount of unaudited pro forma distributable income only as a general indication of the amount of cash available for distribution by the trust for the nine months ended September 30, 2011 and for the year ended December 31, 2010.

 

     Nine Months Ended
September 30, 2011
    Year Ended
December 31,  2010
 
     (In thousands, except per unit data)  
     (Unaudited)     (Unaudited)  

Oil and gas revenues

   $ 79,155      $ 76,898   

Direct operating expenses

     28,906        34,260   
  

 

 

   

 

 

 

Excess of revenues over direct operating expenses

   $ 50,249      $ 42,638   

Less development expenses

     (20,576     (44,000
  

 

 

   

 

 

 

Excess (deficiency) of revenues over direct operating expenses and development expenses

   $ 29,673      $ (1,362

Times Net Profits Interests(1)

     80     80
  

 

 

   

 

 

 

Income (loss) from Net Profits Interests

     23,738        (1,090

Less PCEC operating and services fee

     (724     (903

Reimbursement of excess costs from prior periods(2)

     (2,049       
  

 

 

   

 

 

 

Income (excess cost) from Net Profits Interests

   $ 20,965      $ (1,993
  

 

 

   

 

 

 

Pro forma adjustments:

    

Less trust general and administrative expenses

     (638     (850
  

 

 

   

 

 

 

Cash available for distribution by the trust

   $ 20,327      $ (2,843
  

 

 

   

 

 

 

Cash distribution per trust unit

   $        $     
  

 

 

   

 

 

 

 

(1) Includes no revenues or expenses attributable to the Remaining Properties.

 

(2) The net profits relating to the Developed Properties was a negative amount for the year ended December 31, 2010. The trust is not liable to the owners of the Underlying Properties, PCEC or any other operator for such negative amounts. However, when the net profits relating to the Developed Properties or the Remaining Properties for any computation period is a negative amount, such negative amount plus accrued interest will be deducted from gross proceeds for the Developed Properties or Remaining Properties, as the case may be, in the following computation period for purposes of determining the net profits relating to such properties for the following computation period. Please read “Computation of Net Profits — Net Profits Interests.”

 

 

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Summary Projected Cash Distributions

The following table presents a calculation of forecasted cash distributions to holders of trust units who own the trust units as of the record date for the distribution payable in June 2012 and continue to own trust units through the record date for the distribution payable in May 2013 and was prepared by PCEC based on the assumptions that are described below and in “Projected Cash Distributions—Significant Assumptions Used to Prepare the Projected Cash Distributions.” The trust expects to make its first distribution to unitholders in June 2012, which distribution will cover the proceeds attributable to the Net Profits Interests for April 2012.

PCEC does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of PCEC has prepared the projected financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying projected financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to projected financial information. More specifically, such information omits items that are not relevant to the trust. Neither PricewaterhouseCoopers LLP nor any other independent accountants have examined, compiled or performed any procedures with respect to the accompanying projected financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included in this prospectus relate to the trust, PCEC and PCEC’s predecessor historical financial information. They do not extend to the projected financial information and should not be read to do so.

In the view of PCEC’s management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and judgments of PCEC related to oil and natural gas production, operating expenses and development expenses, settlement of commodity derivative contracts and other general and administrative expenses based on:

 

   

the oil and natural gas production estimates for the twelve months ending March 31, 2013 contained in the reserve reports;

 

   

estimated direct operating expenses and development expenses for the twelve months ending March 31, 2013 contained in the reserve reports;

 

   

projected payments made or received pursuant to the commodity derivative contracts for the twelve months ending March 31, 2013;

 

   

estimated trust general and administrative expenses of $850,000 for the twelve months ending March 31, 2013; and

 

   

an operating and services fee of approximately $1,027,000 for the Developed Properties payable to PCEC for the twelve months ending March 31, 2013.

The projected financial information was based on the hypothetical assumption that prices for oil and natural gas remain constant at $103.00 per Bbl of oil (WTI) and $3.50 per MMBtu of natural gas (Henry Hub) during the twelve-month projection period. Actual prices paid for oil and natural gas expected to be produced from the Underlying Properties during the twelve months ending March 31, 2013 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil and natural gas and variations in basis differentials. For the twelve months ending March 31, 2013, the monthly average forward NYMEX crude oil (WTI) price per Bbl was approximately $102.07 and the monthly average forward NYMEX natural gas (Henry Hub) price per MMBtu was approximately $3.45.

Please read “Projected Cash Distributions—Significant Assumptions Used to Prepare the Projected Cash Distributions,” “Risk Factors—Prices of oil and natural gas fluctuate, and changes in prices could reduce proceeds to the trust and cash distributions to trust unitholders” and “Risk Factors—A delay in the East Coyote and Sawtelle Reversion will result in lower distributions to unitholders than those projected, which would continue until the reversion occurs.”

 

 

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The projections and estimates and the hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of PCEC or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil and natural gas prices. Please read “Risk Factors—Prices of oil and natural gas fluctuate, and changes in prices could reduce proceeds to the trust and cash distributions to trust unitholders.” As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. Please read “Projected Cash Distributions—Sensitivity of Projected Cash Distributions to Oil Production and Prices,” which shows projected effects on cash distributions from hypothetical changes in oil production and prices. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Please read “Risk Factors—The reserves attributable to the Underlying Properties are depleting assets and production from those reserves may diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders may decrease over time.”

The following table presents a calculation of forecasted cash distributions to holders of trust units for the twelve months ending May 31, 2013, which was prepared by PCEC based on the assumptions that are described in “Projected Cash Distributions—Significant Assumptions Used to Prepare the Projected Cash Distributions.” The following table represents amounts associated with the Developed Properties for the projection period but does not include amounts associated with the Remaining Properties because the costs and development expenses associated with such properties exceed revenues associated with such properties for the projection period.

 

Projected Cash Distributions to Trust Unitholders

   Projections for the Twelve
Months Ending

May 31, 2013
 
    

(In thousands,

except per unit data)

 

Underlying Properties sales volumes, net to the trust(1):

  

Oil (MBbl)

     995.3   

Natural gas (MMcf)

     189.6   
  

 

 

 

Total sales (MBoe)

     1,026.9   

Daily production (Boe)

     2,813.3   

Commodity prices(2):

  

Oil (per Bbl)

   $ 103.00   

Natural gas (per MMBtu)

   $ 3.50   

Assumed realized sales prices(3):

  

Oil (per Bbl)

   $ 97.31   

Natural gas (per Mcf)

   $ 2.85   

Net profits, net to the trust:

  

Gross profits(4):

  

Oil sales

   $ 96,853   

Natural gas sales

     540   
  

 

 

 

Total

   $ 97,393   

Costs, net to the trust(5):

  

Direct operating expenses:

  

Lease operating expenses

   $ 29,204   

Production and other taxes

     3,200   

Development expenses(6)

     5,470   
  

 

 

 

Total

   $ 37,874   

Settlement of commodity derivative contracts, net to the trust(7)

       

PCEC operating and services fee(8)

     (1,027
  

 

 

 

Net profits to trust from Net Profits Interests

   $ 58,492   

Trust general and administrative expenses(9)

     (850
  

 

 

 

Cash available for distribution by the trust

   $ 57,642   
  

 

 

 

Cash distribution per trust unit (assumes              units)

   $     
  

 

 

 

 

 

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(1) Sales volumes net to the trust include 80% of sales volumes from the Developed Properties contained in the reserve report for the Underlying Properties.
(2) For a description of the effect of lower crude oil prices on projected cash distributions, please read “Projected Cash Distributions—Sensitivity of Projected Cash Distributions to Oil Production and Prices.”
(3) Sales price net of forecasted gravity, quality, transportation, gathering and processing and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, please read “Projected Cash Distributions—Significant Assumptions Used to Prepare the Projected Cash Distributions.”
(4) Represents “gross profits” as described in “Computation of Net Profits.”
(5) Costs net to the trust include 80% of costs from the Developed Properties contained in the reserve report for the Underlying Properties.
(6) Total development expenses expected to be allocated to the Net Profits Interests for the twelve months ending May 31, 2013 are $12.5 million, of which $7.0 million relates to the Remaining Properties.
(7) Reflects net cash impact of settlements of commodity derivative contracts relating to production. Please read “The Underlying Properties—Commodity Derivative Contracts.”
(8) The PCEC operating and services fee relating to production from the Developed Properties will be charged monthly in an amount equal to $1.00 per Boe of production, which fee will change on an annual basis commencing on April 1, 2013, based on changes to the United States Consumer Price Index, or “CPI.”
(9) Total general and administrative expenses of the trust on an annualized basis for the twelve months ending May 31, 2013 are expected to be $850,000 and will include the annual fees to the trustees, accounting fees, engineering fees, legal fees, printing costs and other expenses properly chargeable to the trust.

Pacific Coast Energy Company LP

PCEC is a privately held Delaware limited partnership formed on June 15, 2004 as BreitBurn Energy Company, L.P. to engage in the production and development of oil and natural gas from properties located in California. As of December 31, 2010, PCEC held interests in approximately 265 gross (204 net) producing wells, and had proved reserves of approximately 33.3 MMBoe.

After giving pro forma effect to the conveyances of the Net Profits Interests to the trust, the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in “Use of Proceeds,” as of September 30, 2011, PCEC would have had total assets of $484.0 million and total liabilities of $36.1 million. For an explanation of the pro forma adjustments, please read “Financial Statements of Pacific Coast Energy Company LP—Unaudited Pro Forma Financial Statements—Introduction.”

The address of PCEC is 515 South Flower Street, Suite 4800, Los Angeles, California 90071, and its telephone number is (213) 225-5900.

 

 

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The Offering

 

Trust units offered by PCEC

             trust units, or              trust units if the underwriters exercise their option to purchase additional trust units in full

 

Trust units owned by PCEC after the offering

             trust units, or              trust units if the underwriters exercise their option to purchase additional trust units in full

 

Trust units outstanding after the offering

             trust units

 

Use of proceeds

PCEC is offering all of the trust units to be sold in this offering, including the trust units to be sold upon any exercise of the underwriters’ option to purchase additional trust units. The estimated net proceeds of this offering to be received by PCEC will be approximately $         million, after deducting underwriting discounts and commissions, structuring fees and expenses, and $         million if the underwriters exercise their option to purchase additional trust units in full. PCEC intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units, to repay amounts outstanding under its senior secured credit agreement and second lien credit agreement, to make a distribution of approximately $         million to the equity owners of PCEC and for general corporate purposes. PCEC is deemed to be an underwriter with respect to the trust units offered hereby. Please read “Use of Proceeds.”

 

Proposed NYSE symbol

“ROYT”

 

Monthly cash distributions

The trust will pay monthly distributions to the holders of trust units as of the applicable record date (generally the last business day of each calendar month) on or before the 10th business day after the record date. The first distribution from the trust to the trust unitholders will be made on or about June 15, 2012 to trust unitholders owning trust units on or about May 31, 2012.

 

  Actual cash distributions to the trust unitholders will fluctuate monthly based upon the quantity of oil and natural gas produced from the Underlying Properties, the prices received for oil and natural gas production, costs to develop and produce the oil and natural gas and other factors. Because payments to the trust will be generated by depleting assets with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties may decline over time. Please read “Risk Factors.”

 

 

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If at any time costs should exceed gross proceeds, neither the trust nor the trust unitholders would be liable for the excess costs. However, the trust would not receive any net profits until future net profits exceed the total of those excess costs, plus interest. The trust calculates the net profits from the Underlying Properties separately for the Developed Properties and the Remaining Properties. Any excess costs for either the Developed Properties or the Remaining Properties will not reduce net profits calculated for the other.

 

Dissolution of the trust

The trust will dissolve upon the earliest to occur of the following: (1) the trust, upon approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interests, (2) the annual cash available for distribution to the trust is less than $2.0 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding trust units vote in favor of dissolution or (4) the trust is judicially dissolved.

 

Estimated ratio of taxable income to distributions

PCEC estimates that a trust unitholder who owns the trust units purchased in this offering through the record date for distributions for the month ending December 31, 2014, will recognize, on a cumulative basis, an amount of federal taxable income for that period of approximately     % of the cash distributed to such trust unitholder with respect to that period. Please read “United States Federal Income Tax Considerations—Direct Taxation of Trust Unitholders” for the basis of this estimate.

 

Summary of income tax consequences

Trust unitholders will be taxed directly on the income from assets of the trust. PCEC and the trust intend to treat the Net Profits Interests, which will be granted to the trust on a perpetual basis, as mineral royalty interests that generate ordinary income subject to depletion for U.S. federal income tax purposes. Please read “United States Federal Income Tax Considerations.”

 

 

15


Table of Contents

RISK FACTORS

Prices of oil and natural gas fluctuate, and changes in prices could reduce proceeds to the trust and cash distributions to trust unitholders.

The trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Prices of oil and natural gas can fluctuate widely in response to a variety of factors that are beyond the control of the trust and PCEC. These factors include, among others:

 

   

regional, domestic and foreign supply and perceptions of supply of oil and natural gas;

 

   

the level of demand and perceptions of demand for oil and natural gas;

 

   

political conditions or hostilities in oil and natural gas producing countries;

 

   

anticipated future prices of oil and natural gas and other commodities;

 

   

weather conditions and seasonal trends;

 

   

technological advances affecting energy consumption and energy supply;

 

   

U.S. and worldwide economic conditions;

 

   

the price and availability of alternative fuels;

 

   

the proximity, capacity, cost and availability of gathering and transportation facilities;

 

   

the volatility and uncertainty of regional pricing differentials;

 

   

governmental regulations and taxation;

 

   

energy conservation and environmental measures;

 

   

level and effect of trading in commodity futures markets, including by commodity price speculators; and

 

   

acts of force majeure.

Crude oil prices declined from record high levels in early July 2008 of over $140 per Bbl to below $45 per Bbl in February 2009. In November 2011, crude oil prices ranged from $92.19 per Bbl to $102.59 per Bbl. Natural gas prices declined from over $13.57 per MMBtu in July 2008 to below $3.30 per MMBtu in October 2010. In November 2011, natural gas prices ranged from $2.84 per MMBtu to $3.55 per MMBtu.

Changes in the prices of oil and natural gas may reduce profits to which the trust is entitled and may ultimately reduce the amount of oil and natural gas that is economic to produce from the Underlying Properties. As a result, PCEC could determine during periods of low commodity prices to shut in or curtail production from wells on the Underlying Properties. In addition, PCEC or any third party operator could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, PCEC or any third party operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the Net Profits Interests relating to the abandoned well or property.

The Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, a decrease in commodity prices may cause the expenses of certain wells to exceed the well’s revenue. If this scenario were to occur, PCEC or any third party operator may decide to shut-in the well or plug and abandon the well. This scenario could reduce future cash distributions to trust unitholders. In addition, PCEC is also sensitive to increasing natural gas prices at its Orcutt properties, where it consumes natural gas in connection with its production of oil. Accordingly, at

 

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times when PCEC is a net buyer of natural gas, increases in the price of natural gas may reduce proceeds from production from PCEC’s Orcutt Diatomite properties and could reduce future cash distributions to trust unitholders.

PCEC intends to enter into commodity derivative contracts with respect to 50% to 70% of expected production of oil for 2012 and 2013 from the proved developed reserves attributable to the Underlying Properties in the reserve reports. The commodity derivative contracts are intended to reduce exposure of the revenues from oil production from the Underlying Properties to fluctuations in oil prices and to achieve more predictable cash flow. Some of the commodity derivative contracts could limit the benefit to the trust of any increase in oil prices through 2013. The trust will be required to bear its share of the hedge payments regardless of whether the corresponding quantities of oil are produced or sold. Furthermore, PCEC does not intend to enter into any commodity derivative contracts affecting the trust relating to oil volumes expected to be produced after 2013, and the terms of the conveyances of the Net Profits Interests will prohibit PCEC from entering into new hedging arrangements burdening the trust following the completion of this offering. As a result, the amount of the cash distributions will be subject to a greater fluctuation after 2013 due to changes in oil prices. For a discussion of the commodity derivative contracts, please read “The Underlying Properties—Commodity Derivative Contracts.”

Estimates of future cash distributions to trust unitholders are based on assumptions that are inherently subjective.

The projected cash distributions to trust unitholders for the twelve months ending May 31, 2013 contained elsewhere in this prospectus are based on PCEC’s calculations, and PCEC has not received an opinion or report on such calculations from any independent accountants or engineers. Such calculations are based on assumptions about drilling, production, crude oil and natural gas prices, hedging activities, development expenses, and other matters that are inherently uncertain and are subject to significant business, economic, financial, legal, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those estimated. In particular, these estimates have assumed that crude oil and natural gas production is sold in 2012 and 2013 based on assumed NYMEX prices of $103.00 per Bbl in the case of crude oil and $3.50 per MMBtu in the case of natural gas. However, actual sales prices may be significantly lower. Additionally, these estimates assume the Underlying Properties will achieve production volumes set forth in the reserve reports; however, actual production volumes may be significantly lower. If prices or production are lower than expected, the amount of cash available for distribution to trust unitholders would be reduced.

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the trust and the value of the trust units.

The value of the trust units and the amount of future cash distributions to the trust unitholders will depend upon, among other things, the accuracy of the reserves and future production estimated to be attributable to the trust’s interest in the Underlying Properties. Please read “The Underlying Properties—Reserve Reports” for a discussion of the method of allocating proved reserves to the Underlying Properties and the Net Profits Interests. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary both positively and negatively and in material amounts from estimates. Furthermore, direct operating expenses and development expenses relating to the Underlying Properties could be substantially higher than current estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:

 

   

historical production from the area compared with production rates from other producing areas;

 

   

oil and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and development expenses; and

 

   

the assumed effect of expected governmental regulation and future tax rates.

 

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Changes in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties may decrease in the future as a result of future decreases in the price of oil or natural gas.

A delay in the East Coyote and Sawtelle Reversion will result in lower distributions to unitholders than those projected, which would continue until the reversion occurs.

The projected cash distributions to trust unitholders and the reserve reports each assume that PCEC’s working interests in the East Coyote and Sawtelle properties will increase in April 2012. PCEC currently holds an average working interest of approximately 5.0% in the East Coyote and Sawtelle properties. PCEC holds a reversionary interest in both of these fields, and its average working interest will increase to approximately 37.6% once certain payment milestones are achieved, which PCEC expects to occur in April 2012. At this time, PCEC’s share of production from its East Coyote and Sawtelle properties is 23 and 41 Boe/d, respectively, and would increase to 186 and 152 Boe/d, respectively, following the East Coyote and Sawtelle Reversion. Delays in the timing of the East Coyote and Sawtelle Reversion could be caused by, among other things, production issues and decreases in the price of oil and natural gas, and hence the timing of the reversion is beyond PCEC’s control.

Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to trust unitholders.

The process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous risks beyond the trust’s or PCEC’s control, including risks that could delay PCEC’s or other third party operators’ current drilling or production schedule and the risk that drilling will not result in commercially viable oil or natural gas production. PCEC is not obligated to undertake any development activities, and, as a result, any drilling or completion activities will be subject to the reasonable discretion of PCEC. The ability of PCEC or any third party operator to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:

 

   

delays imposed by or resulting from compliance with regulatory requirements, including permitting;

 

   

unusual or unexpected geological formations;

 

   

shortages of or delays in obtaining equipment and qualified personnel;

 

   

lack of available gathering facilities or delays in construction of gathering facilities;

 

   

lack of available capacity on interconnecting transmission pipelines;

 

   

equipment malfunctions, failures or accidents;

 

   

unexpected operational events and drilling conditions;

 

   

reductions in oil or natural gas prices;

 

   

market limitations for oil or natural gas;

 

   

pipe or cement failures;

 

   

casing collapses;

 

   

lost or damaged drilling and service tools;

 

   

loss of drilling fluid circulation;

 

   

uncontrollable flows of oil and natural gas, insert gas, water or drilling fluids;

 

   

fires and natural disasters;

 

   

environmental hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases;

 

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adverse weather conditions; and

 

   

oil or natural gas property title problems.

In the event that planned operations, including drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, estimated future distributions to trust unitholders may be reduced. In the event PCEC or any third party operator incurs increased costs due to one or more of the above factors or for any other reason and is not able to recover such costs from insurance, the estimated future distributions to trust unitholders may be reduced.

The trust is passive in nature and neither the trust nor the trust unitholders will have any ability to influence PCEC or control the operations or development of the Underlying Properties.

The trust units are a passive investment that entitle the trust unitholder to only receive cash distributions from the Net Profits Interests and commodity derivative contracts being conveyed to the trust. Trust unitholders have no voting rights with respect to PCEC and, therefore, will have no managerial, contractual or other ability to influence PCEC’s activities or the operations of the Underlying Properties. PCEC operated approximately 98% of the average daily production from the Underlying Properties for the month ended September 30, 2011 and is generally responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect such properties. Accordingly, PCEC may take actions that are in its own interests that may be different from the interests of the trust.

Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the amount of cash available for distribution to the trust unitholders.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability of PCEC or any third party operator to conduct the operations which it currently has planned for the Underlying Properties, which would reduce the amount of cash received by the trust and available for distribution to the trust unitholders.

The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.

The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interests and the distributions to trust unitholders. PCEC does not obtain title insurance covering mineral leaseholds, and PCEC’s failure to cure any title defects may cause PCEC to lose its rights to production from the Underlying Properties. In the event of any such material title problem, profits available for distribution to trust unitholders and the value of the trust units may be reduced.

PCEC may transfer all or a portion of the Underlying Properties at any time without trust unitholder consent.

PCEC may at any time transfer all or part of the Underlying Properties, subject to and burdened by the Net Profits Interests, and may abandon individual wells or properties reasonably believed to be uneconomic. Trust unitholders will not be entitled to vote on any transfer or abandonment of the Underlying Properties, and the trust

 

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will not receive any profits from any such transfer. Please read “The Underlying Properties—Sale and Abandonment of Underlying Properties.” Following any sale or transfer of any of the Underlying Properties, the Net Profits Interests will continue to burden the transferred property and net profits attributable to such property will be calculated as part of the computation of net profits described in this prospectus. PCEC may delegate to the transferee responsibility for all of PCEC’s obligations relating to the Net Profits Interests on the portion of the Underlying Properties transferred.

PCEC may, without the consent of the trust unitholders, require the trust to release the Net Profits Interests associated with any property that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior twelve months and provided that the Net Profits Interests covered by such releases cannot exceed, during any twelve month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by PCEC of the relevant Underlying Properties and are conditioned upon an amount equal to the fair market value (net of sales costs) of such Net Profits Interests being treated as an offset amount against costs and expenses. PCEC has not identified for sale any of the Underlying Properties.

PCEC may enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval of the trustee or any trust unitholder.

PCEC may be unable to successfully renegotiate its administrative services agreement with BreitBurn Management LLC, a wholly owned subsidiary of BBEP, which failure would require PCEC to hire its own management and other employees.

The completion of this offering may result in a termination event under the administrative services agreement between PCEC and BreitBurn Management LLC, a wholly owned subsidiary of BBEP. If the administrative services agreement were terminated, PCEC would be required to hire its own management and other employees. There can be no assurances that PCEC will be able to hire management with similar experience or for similar cost as under its administrative services agreement. While PCEC intends to renegotiate the administrative services agreement with the BBEP board of directors, there can be no assurance that such renegotiation will be successful.

The reserves attributable to the Underlying Properties are depleting assets and production from those reserves may diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders may decrease over time.

The profits payable to the trust attributable to the Net Profits Interests are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties may decline over time.

Future maintenance projects on the Underlying Properties may affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties. The timing and size of these projects will depend on, among other factors, the market prices of oil and natural gas. Furthermore, with respect to properties for which PCEC is not designated as the operator, PCEC has limited control over the timing or amount of those development expenses. PCEC also has the right to non-consent and not participate in the development expenses on properties for which it is not the operator, in which case PCEC and the trust will not receive the production resulting from such development expenses until after payout occurs pursuant to the applicable joint operating agreements. If PCEC or any third party operator does not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by PCEC or estimated in the reserve reports.

 

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The trust agreement will provide that the trust’s activities will be limited to owning the Net Profits Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Net Profits Interests. As a result, the trust will not be permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the Net Profits Interests.

Because the net profits payable to the trust are derived from the sale of depleting assets, the portion of the distributions to trust unitholders attributable to depletion may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the Underlying Properties burdened by the Net Profits Interests may cease to produce in commercially paying quantities and the trust may, therefore, cease to receive any distributions of net profits therefrom.

A change in crude oil price differentials may adversely impact the cash distributions available to trust unitholders.

PCEC’s crude oil production is sold in the local markets where the pricing is based on local or regional supply and demand factors. The prices that PCEC receives for its crude oil production have recently been higher than common benchmark prices, such as WTI. The difference between the benchmark price and the price PCEC receives is called a differential. PCEC cannot predict how the differential applicable to its production will change in the future, and it is possible that the prices received for PCEC’s oil production may decrease. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the mid-stream or downstream sectors of the industry, trade restrictions and governmental regulations. Changes in the differential between common benchmark prices for oil and the wellhead price PCEC receives could adversely impact the cash distributions available to trust unitholders.

The amount of cash available for distribution by the trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the trust.

The trust will indirectly bear an 80% share of all costs and expenses related to the production from the Developed Properties and a 25% share of all costs and expenses related to the production from the Remaining Properties. These costs and expenses include direct operating expenses, development expenses and hedge expenses, which will reduce the amount of cash received by the trust and thereafter distributable to trust unitholders. Accordingly, higher costs and expenses related to the Underlying Properties will directly decrease the amount of cash received by the trust in respect of a Net Profits Interest. Please read “Computation of Net Profits.” Historical costs may not be indicative of future costs. For example, PCEC may in the future propose additional drilling projects that significantly increase the capital expenditures associated with the Underlying Properties, which could reduce cash available for distribution by the trust. In addition, cash available for distribution by the trust will be further reduced by the trust’s general and administrative expenses, which are expected to be approximately $850,000 for the twelve months ending March 31, 2013, and by the PCEC operating and services fee which will be an amount equal to $1.00 per Boe of production and which is expected to be approximately $1,027,000 for the same period (an additional $8,000 is expected to accrue for the Remaining Properties). The PCEC operating and services fee will change on an annual basis commencing on April 1, 2013, based on changes to the CPI. For details about the trust’s general and administrative expenses and the PCEC operating and services fee, please read “Description of the Trust Agreement—Fees and Expenses.”

Net profits payable to the trust depend upon production quantities, sales prices of oil and natural gas and costs to develop and produce the oil and natural gas. If at any time costs should exceed gross proceeds, neither the trust nor the trust unitholders would be liable for the excess costs. However, the trust would not receive any net profits until future net profits exceed the total of those excess costs, plus interest. The trust calculates the net profits from the Underlying Properties separately for each of the Developed Properties and the Remaining Properties. Any excess costs for either the Developed Properties or the Remaining Properties will not reduce net profits calculated for the other.

 

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The generation of profits for distribution by the trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.

The marketability of PCEC’s oil and natural gas production depends in part upon the availability, proximity and capacity of gathering, transportation and processing facilities owned by third parties. In general, PCEC does not control these third-party facilities and its access to them may be limited or denied due to circumstances beyond its control. A significant disruption in the availability of these facilities could adversely impact PCEC’s ability to deliver to market the oil and natural gas it produces and thereby cause a significant interruption in PCEC’s operations. In some cases, PCEC’s ability to deliver to market its oil and natural gas is dependent upon coordination among third parties who own the transportation and processing facilities it uses, and any inability or unwillingness of those parties to coordinate efficiently could also interrupt PCEC’s operations. These are risks for which PCEC generally does not maintain insurance.

The facilities at PCEC’s West Pico, East Coyote and Sawtelle properties are located in urban settings. The available means for alternative transportation of production from these properties are limited, due to the difficulties of building transportation systems in these areas as well as permitting restrictions pertaining to trucking. In addition, PCEC’s Orcutt properties are currently serviced by a single gathering system, and there are a limited number of other transportation alternatives in the area. A change in PCEC’s current takeaway arrangements, in the absence of a satisfactory alternatives, would have an adverse effect on PCEC’s operations. PCEC would be similarly affected if any of the other transportation, gathering and processing facilities it uses became unavailable or unable to provide services.

ConocoPhillips purchases a significant percentage of PCEC’s production, and a decision by ConocoPhillips to discontinue or reduce its purchases of PCEC’s production may adversely impact the cash distributions available to trust unitholders.

In 2010 and 2009, ConocoPhillips purchased 97% of PCEC’s production. If ConocoPhillips were to no longer purchase PCEC’s production, or were to significantly reduce the amount of production it purchases, the cash distributions available to trust unitholders may be adversely impacted.

The trustee must, under certain circumstances, sell the Net Profits Interests and dissolve the trust prior to the expected termination of the trust. As a result, trust unitholders may not recover their investment.

The trustee must sell the Net Profits Interests and dissolve the trust if the holders of at least 75% of the outstanding trust units approve the sale or vote to dissolve the trust. The trustee must also sell the Net Profits Interests and dissolve the trust if the annual gross profits from the Underlying Properties attributable to the Net Profits Interests are less than $2.0 million for each of any two consecutive years. The net profits of any such sale will be distributed to the trust unitholders.

PCEC may sell trust units in the public or private markets, and such sales could have an adverse impact on the trading price of the trust units.

After the closing of the offering, PCEC will hold an aggregate of              trust units, assuming no exercise of the underwriters’ option to purchase additional trust units. PCEC has agreed not to sell any trust units for a period of 180 days after the date of this prospectus unless Barclays Capital Inc. consents to a shorter period. Please read “Underwriting.” After such period, PCEC may sell trust units in the public or private markets, and any such sales could have an adverse impact on the price of the trust units or on any trading market that may develop. The trust has granted registration rights to PCEC, which, if exercised, would facilitate sales of trust units by PCEC.

 

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There has been no public market for the trust units, and accordingly the value after this offering may differ from the price in the offering.

The initial public offering price of the trust units will be determined by negotiation among PCEC and the underwriters. Among the factors to be considered in determining the number of trust units to be offered hereby and the initial public offering price will be estimates of distributions to trust unitholders; overall quality of the oil and natural gas properties attributable to the Underlying Properties; the history and prospects for the energy industry; PCEC’s financial information; the prevailing securities markets at the time of this offering and the recent market prices of, and the demand for, publicly traded units of royalty trusts. None of PCEC, the trust or the underwriters will obtain any independent appraisal or other opinion of the value of the Net Profits Interests, other than the reserve reports prepared by Netherland Sewell.

The trading price for the trust units may not reflect the value of the Net Profits Interests held by the trust, which would adversely affect the return on an investment in the units.

The trading price for publicly traded securities similar to the trust units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the trust will vary in response to numerous factors outside the control of the trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development expenses. Consequently, the market price for the trust units may not necessarily be indicative of the value that the trust would realize if it sold the Net Profits Interests to a third-party buyer. In addition, such market price may not necessarily reflect the fact that since the assets of the trust are depleting assets, a portion of each cash distribution paid with respect to the trust units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the trust unitholder.

Conflicts of interest could arise between PCEC and its affiliates, on the one hand, and the trust and the trust unitholders, on the other hand, which could harm the business or financial results of the trust.

As working interest owners in, and the operators of substantially all wells on, the Underlying Properties, PCEC and its affiliates could have interests that conflict with the interests of the trust and the trust unitholders. For example:

 

   

PCEC’s interests may conflict with those of the trust and the trust unitholders in situations involving the development, maintenance, operation or abandonment of certain wells on the Underlying Properties for which PCEC acts as the operator. PCEC may also make decisions with respect to development expenses that adversely affect the Underlying Properties. These decisions include reducing development expenses for those properties for which PCEC acts as the operator, which could cause oil and natural gas production to decline at a faster rate and thereby result in lower cash distributions by the trust in the future.

 

   

PCEC may sell some or all of the Underlying Properties without taking into consideration the interests of the trust unitholders. Such sales may not be in the best interests of the trust unitholders and the purchasers may lack PCEC’s experience or its credit worthiness. PCEC also has the right, under certain circumstances, to cause the trust to release all or a portion of the Net Profits Interests in connection with a sale of a portion of the Underlying Properties to which such Net Profits Interests relates. In such an event, the trust is entitled to receive the fair market value (net of sales costs) of the Net Profits Interests released, which will be treated as an offset amount against costs and expenses. Please read “The Underlying Properties—Sale and Abandonment of Underlying Properties.”

 

   

PCEC has registration rights and can sell its trust units without considering the effects such sale may have on trust unit prices or on the trust itself. Additionally, PCEC can vote its trust units in its sole discretion without considering the interests of the other trust unitholders. PCEC is not a fiduciary with respect to the trust unitholders or the trust and will not owe any fiduciary duties or liabilities to the trust unitholders or the trust.

 

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The trust is managed by a trustee who cannot be replaced except by a majority vote of the trust unitholders at a special meeting, which may make it difficult for trust unitholders to remove or replace the trustee.

The affairs of the trust will be managed by the trustee. Your voting rights as a trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust agreement provides that the trustee may only be removed and replaced by the holders of a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present, including trust units held by PCEC, called by either the trustee or the holders of not less than 10% of the outstanding trust units. As a result, it will be difficult for public trust unitholders to remove or replace the trustee without the cooperation of PCEC so long as it holds a significant percentage of total trust units.

Trust unitholders have limited ability to enforce provisions of the conveyances creating the Net Profits Interests, and PCEC’s liability to the trust is limited.

The trust agreement permits the trustee to sue PCEC or any other future owner of the Underlying Properties to enforce the terms of the conveyances creating the Net Profits Interests. If the trustee does not take appropriate action to enforce provisions of the conveyances, trust unitholders’ recourse would be limited to bringing a lawsuit against the trustee to compel the trustee to take specified actions. The trust agreement expressly limits a trust unitholder’s ability to directly sue PCEC or any other third party other than the trustee. As a result, trust unitholders will not be able to sue PCEC or any future owner of the Underlying Properties to enforce these rights. Furthermore, the conveyances creating the Net Profits Interests provide that, except as set forth in the conveyances, PCEC will not be liable to the trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct.

Courts outside of Delaware may not recognize the limited liability of the trust unitholders provided under Delaware law.

Under the Delaware Statutory Trust Act, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to trust unitholders.

The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations that apply to the operations on the Underlying Properties, including the requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use; the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. For example, the U.S. Environmental Protection Agency, or “EPA,” has proposed regulations to impose more stringent emissions control requirements for oil and gas development and production operations, which may require PCEC, its operators, or third-party contractors to incur additional expenses to control air emissions from current operations and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other requirements. Any such requirements could increase the costs of development and production, reducing the profits available to the trust and potentially impairing the economic development of the Underlying Properties.

 

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In addition, PCEC’s plan to increase production in the Diatomite beyond the currently-permitted wells will require additional permits and approvals from various state, federal and local agencies, in addition to a new review under the California Environmental Quality Act. Such a process could take several months or possibly longer, and there can be no assurance that such permits would be timely obtained or on terms and conditions consistent with PCEC’s proposed plan.

For all of PCEC’s operations, numerous governmental authorities such as the EPA, analogous state agencies such as the California Department of Conservation, Division of Oil, Gas and Geothermal Resources, or “DOGGR,” and local agencies such as the County of Santa Barbara Planning and Development, Energy Division, have the power to enforce compliance with these laws and regulations and the permits issued under them, often times requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and gas wastes, could impair PCEC’s ability to produce oil and natural gas commercially from the Underlying Properties, which would reduce profits attributable to the Net Profits Interests.

There is inherent risk of incurring significant environmental costs and liabilities in the operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, PCEC could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether PCEC was responsible for the release or contamination or whether PCEC was in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose PCEC to significant liabilities that could have a material adverse effect on PCEC’s business, financial condition and results of operations and could reduce the amount of cash available for distribution to trust unitholders. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require PCEC to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition. PCEC may be unable to recover some or any of these costs from insurance, in which case the amount of cash received by the trust may be decreased. The trust will indirectly bear an 80% share of all costs and expenses related to the production from the Developed Properties and a 25% share of all costs and expenses related to the production from the Remaining Properties, including those related to environmental compliance and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to PCEC’s acquisition of the Underlying Properties unless such costs and expenses result from the operator’s negligence or misconduct. In addition, as a result of the increased cost of compliance, PCEC may decide to discontinue drilling.

The operations of the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to trust unitholders.

The production and development operations on the Underlying Properties are subject to complex and stringent laws and regulations. In order to conduct its operations in compliance with these laws and regulations, PCEC must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. PCEC may incur substantial

 

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costs and experience delays in order to maintain compliance with these existing laws and regulations, and the trust’s income will be reduced by its 80% share of such costs related to the production from the Developed Properties and a 25% share of such costs related to the production from the Remaining Properties. In addition, PCEC’s costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to its operations. Such costs could have a material adverse effect on PCEC’s business, financial condition and results of operations and reduce the amount of cash received by the trust in respect of the Net Profits Interests. For example, in California, there have been proposals at the legislative initiative and executive levels over the past two years for tax increases which have included a severance tax as high as 15% on all oil production in California. Although the proposals have not passed the California legislature, the financial crisis in the State of California could lead to a severance tax on oil being imposed in the future. While PCEC cannot predict the impact of such a tax given the uncertainty of the proposals, the imposition of such a tax could have severe negative impacts on both our willingness and ability to incur capital expenditures to increase production, could severely reduce or completely eliminate PCEC’s profit margins and would result in lower oil production in PCEC’s properties due to the need to shut-in wells and facilities made uneconomic either immediately or at an earlier time than would have previously been the case. PCEC must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets.

Laws and regulations governing exploration and production may also affect production levels. PCEC is required to comply with federal and state laws and regulations governing conservation matters, including:

 

   

provisions related to the unitization or pooling of oil and natural gas properties;

 

   

the spacing of wells;

 

   

the plugging and abandonment of wells; and

 

   

the removal of related production equipment.

Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of PCEC and third party downstream oil and natural gas transporters. These and other laws and regulations can limit the amount of oil and natural gas PCEC can produce from its wells, limit the number of wells it can drill, or limit the locations at which it can conduct drilling operations, which in turn could negatively impact trust distributions, estimated and actual future net revenues to the trust and estimates of reserves attributable to the trust’s interests.

New laws or regulations, or changes to existing laws or regulations, may unfavorably impact PCEC, could result in increased operating costs or have a material adverse effect on its financial condition and results of operations and reduce the amount of cash received by the trust. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations could increase the operating costs of PCEC, reduce its liquidity, delay its operations or otherwise alter the way PCEC conducts its business, any of which could have a material adverse effect on the trust and the amount of cash available for distribution to trust unitholders.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that PCEC produces while the physical effects of climate change could disrupt their production and cause it to incur significant costs in preparing for or responding to those effects.

The oil and gas industry is a direct source of certain greenhouse gas, or “GHG,” emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact future operations on the Underlying Properties. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and

 

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other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the Earth’s atmosphere and other climate changes. Based on these findings, the agency has begun adopting and implementing regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. During 2010, the EPA adopted two sets of rules regulating GHG emissions under the Clean Air Act, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration, or “PSD,” and Title V permitting programs. The stationary source rule “tailors” these permitting programs to apply to certain stationary sources in a multi-step process, with the largest sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHGs that will be established by the states or, in some instances, by the EPA on a case-by-case basis. These EPA rulemakings could affect the operations on the Underlying Properties or the ability of PCEC to obtain air permits for new or modified facilities. In addition, on November 30, 2010, the EPA published final regulations expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from the equipment or operations of PCEC could require PCEC to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with its operations. Such requirements could also adversely affect demand for the oil and natural gas produced, all of which could reduce profits attributable to the Net Profits Interests and, as a result, the trust’s cash available for distribution.

In addition, the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, and almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These reductions would be expected to cause the cost of allowances to escalate significantly over time.

For example, California enacted AB32, the Global Warming Solutions Act of 2006, which established the first statewide program in the United States to limit GHG emissions and impose penalties for non-compliance. Since then, the California Air Resources Board, or “CARB,” has taken and plans to take various actions to implement the program, including the approval on December 11, 2008, of an AB32 Scoping Plan summarizing the main GHG-reduction strategies for California. In October 2011, the CARB adopted the final cap-and-trade regulation, including a delay in the start of the cap-and-trade rule’s compliance obligations until 2013. The final cap-and-trade system is designed to be in conjunction with the Western Climate Initiative, which currently includes seven states and four Canadian provinces. Because oil production operations emit GHGs, PCEC’s operations in California are subject to regulations issued under AB32. These regulations increase PCEC’s costs for those operations and adversely affect its operating results. Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact PCEC and the trust. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, PCEC cannot predict the financial impact of related developments on PCEC or the trust.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on PCEC’s assets and operations and, consequently, may reduce profits attributable to the Net Profits Interests and, as a result, the trust’s cash available for distribution.

 

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Recent regulatory changes in California have and may continue to negatively impact PCEC’s production in its Diatomite properties.

Recent regulatory changes in California have impacted PCEC’s Diatomite production. In 2010, Diatomite production decreased significantly due to the inability to drill new wells pending the receipt of permits from the DOGGR. PCEC has approval under these new regulations for its current Diatomite drilling program, though the drilling of additional wells will require additional approval. The current approval, among other things, includes stringent operating, response and preventative requirements relating to mechanical integrity testing and responses to integrity issues and surface expressions, among others. Compliance with these requirements and delays in regulatory reviews, as well as other regulatory action and inaction, may negatively impact the pace of drilling and steam injection and may impact development from the Orcutt Diatomite property in the near term. PCEC may not be successful in streamlining the review process with the DOGGR or in taking additional steps to more efficiently manage operations to avoid additional delays. PCEC’s production activities in the Diatomite zone have resulted in crude oil from the near-surface Careaga zone reaching the surface in various locations. PCEC controls such surface expressions by balancing the amount of fluids injected and withdrawn into the Diatomite zone. However, in areas where surface expressions still occur, the crude oil is collected through a surface gathering system. In addition, two wells in the field have developed casing leaks that allowed steam to reach the surface. The DOGGR may impose additional operational restrictions or requirements, including requiring that wells be shut in, as a result of incidents involving surface expressions. PCEC is allowed to produce at the Orcutt properties despite surface expressions pursuant to a field order issued by DOGGR. This field order is subject to change or revocation by DOGGR at its sole discretion. Production from PCEC’s Orcutt Diatomite property averaged 649 Boe/d during September 2011.

The bankruptcy of PCEC or any third party operator could impede the operation of wells and the development of proved undeveloped reserves.

The value of the Net Profits Interests and the trust’s ultimate cash available for distribution will be highly dependent on PCEC’s financial condition. Neither PCEC nor any of the other operators of the Underlying Properties has agreed with the trust to maintain a certain net worth or to be restricted by other similar covenants, and PCEC intends to use a portion of the net proceeds of this offering to repay indebtedness and for general corporate purposes instead of retaining all or a portion to pay costs for the operation and development of the Underlying Properties.

The ability to develop and operate the Underlying Properties depends on PCEC’s future financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of PCEC. Please read “Information about Pacific Coast Energy Company LP” for additional information relating to PCEC, including information relating to the business of PCEC, historical financial statements of PCEC and other financial information relating to PCEC. PCEC will not be a reporting company following this offering and will not be required to file periodic reports with the SEC pursuant to the Securities Exchange Act of 1934, as amended, or the “Exchange Act.” Therefore, as a trust unitholder, you will not have access to financial information about PCEC.

In the event of the bankruptcy of PCEC or any third party operator of the Underlying Properties, the working interest owners in the affected properties, creditors or the debtor-in-possession will have to seek a new party to perform the development and the operations of the affected wells. PCEC or the other working interest owners may not be able to find a replacement driller or operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period of time. As a result, such a bankruptcy may result in reduced production of reserves and decreased distributions to trust unitholders.

 

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Due to the trust’s lack of industry and geographic diversification, adverse developments in California could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributions to trust unitholders.

The operations of the Underlying Properties are focused exclusively on the production and development of oil and natural gas within the state of California. As a result, the results of operations and cash flows of the Underlying Properties depend upon continuing operations in this area. This concentration could disproportionately expose the trust’s interests to operational and regulatory risk in this area. Due to the lack of diversification in geographic location, adverse developments in exploration and production of oil and natural gas in this area of operation could have a significantly greater impact on the results of operations and cash flows of the Underlying Properties than if the operations were more diversified.

The receipt of payments by PCEC based on any commodity derivative contract will depend upon the financial position of commodity derivative contract counterparties. A default by any commodity derivative contract counterparties could reduce the amount of cash available for distribution to the trust unitholders.

Payments from any commodity derivative contract counterparties to PCEC will be intended to offset costs and thus have the effect of providing additional cash to the trust during periods of lower crude oil prices. In the event that any of the counterparties to commodity derivative contracts default on their obligations to make payments to PCEC under the commodity derivative contracts, the cash distributions to the trust unitholders could be materially reduced. PCEC does not have any security interest from its hedge counterparties against which it could recover in the event of a default by any such counterparty.

Tax Risks Related to the Trust’s Trust Units

The trust has not requested a ruling from the IRS regarding the tax treatment of the trust. If the IRS were to determine (and be sustained in that determination) that the trust is not a “grantor trust” for federal income tax purposes, the trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to trust unitholders.

If the trust were not treated as a grantor trust for federal income tax purposes, the trust may be properly classified as a partnership for such purposes. Although the trust would not become subject to federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the trust unitholders, the trust’s tax compliance requirements would be more complex and costly to implement and maintain, and its distributions to trust unitholders could be reduced as a result.

Neither PCEC nor the trustee has requested a ruling from the IRS regarding the tax status of the trust, and neither PCEC nor the trust can assure you that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.

Trust unitholders should be aware of the possible state tax implications of owning trust units. Please read “State Tax Considerations.”

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

Among the items affected by President Obama’s Budget Proposal for Fiscal Year 2012, or the “Budget Proposal,” are certain key U.S. federal income tax preferences relating to oil and natural gas exploration and production. Legislation has been proposed that includes proposals from the Budget Proposal that would, if enacted, materially revise certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for United States production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in

 

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connection with the exploration for, or development of, oil or gas within the United States. It is unclear whether any such changes will actually be enacted into law or, if enacted, how soon any such changes could become effective. The passage of any such legislation, or any other similar changes in U.S. federal income tax laws that eliminate certain tax preferences that are currently available with respect to oil and natural gas exploration and production, could reduce the cash available for distribution to the trust unitholders or adversely affect the value of the trust units.

You will be required to pay taxes on your share of the trust’s income even if you do not receive any cash distributions from the trust.

Trust unitholders are treated as if they own the trust’s assets and receive the trust’s income and are directly taxable thereon as if no trust were in existence. Because the trust will generate taxable income that could be different in amount than the cash the trust distributes, you will be required to pay any federal and applicable California income taxes and, in some cases, other state and local income taxes on your share of the trust’s taxable income even if you receive no cash distributions from the trust. You may not receive cash distributions from the trust equal to your share of the trust’s taxable income or even equal to the actual tax liability that results from that income.

A portion of any tax gain on the disposition of the trust units could be taxed as ordinary income.

If you sell your trust units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those trust units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture. Please read “United States Federal Income Tax Considerations—Tax Consequences to U.S. Trust Unitholders—Disposition of Trust Units.”

The trust will allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the trust unitholders.

The trust will generally allocate its items of income, gain, loss and deduction between transferors and transferees of the trust units each month based upon the ownership of the trust units on the monthly record date, instead of on the basis of the date a particular trust unit is transferred. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the trust unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods. Please read “United States Federal Income Tax Considerations—Direct Taxation of Trust Unitholders.”

As a result of investing in trust units, you may become subject to state and local taxes and return filing requirements in California.

In addition to federal income taxes, trust unitholders will likely be subject to other taxes, including state and local taxes that are imposed in California, where the Underlying Properties are located, even if the trust unitholders do not live in California. Trust unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in California. Further, trust unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each trust unitholder to file all federal, state and local tax returns.

 

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FORWARD-LOOKING STATEMENTS

This prospectus contains “forward-looking statements” about PCEC and the trust that are subject to risks and uncertainties. All statements other than statements of historical fact included in this prospectus, including, without limitation, statements under “Prospectus Summary” and “Risk Factors” regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the future operations of PCEC and the trust, are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. Forward-looking statements are subject to risks and uncertainties and include statements made in this prospectus under “Projected Cash Distributions,” statements pertaining to future development activities and costs, and other statements in this prospectus that are prospective and constitute forward-looking statements.

When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this prospectus, could affect the future results of the energy industry in general, and PCEC and the trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

 

   

risks associated with the drilling and operation of oil and natural gas wells;

 

   

the amount of future direct operating expenses and development expenses;

 

   

the effect of existing and future laws and regulatory actions;

 

   

the effect of changes in commodity prices or in alternative fuel prices;

 

   

the impact of any commodity derivative contracts;

 

   

conditions in the capital markets;

 

   

competition from others in the energy industry;

 

   

uncertainty of estimates of oil and natural gas reserves and production; and

 

   

cost inflation.

You should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this prospectus. Neither PCEC nor the trust undertakes any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this prospectus or to reflect the occurrence of unanticipated events, unless the securities laws require it to do so.

This prospectus describes other important factors that could cause actual results to differ materially from expectations of PCEC and the trust, including under the heading “Risk Factors.” All written and oral forward-looking statements attributable to PCEC, the trust, or persons acting on behalf of PCEC or the trust are expressly qualified in their entirety by such factors.

 

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USE OF PROCEEDS

PCEC is offering all of the trust units to be sold in this offering, including the trust units to be sold upon the exercise of the underwriters’ option to purchase additional trust units. PCEC expects to receive net proceeds from the sale of             trust units offered by this prospectus of approximately $         million, after deducting underwriting discounts and commissions, structuring fees and offering expenses, and an additional $         million if the underwriters exercise their option to purchase additional trust units in full. PCEC is deemed to be an underwriter with respect to the trust units offered hereby.

PCEC intends to use the net proceeds from this offering, including any proceeds from the exercise of the underwriters’ option to purchase additional trust units, to repay borrowings outstanding under its senior secured credit agreement and second lien credit agreement, to make a distribution to the equity owners of PCEC and for general corporate purposes. The table below sets forth these intended uses with the corresponding dollar amounts planned for such use, assuming no exercise of the underwriters’ over-allotment option.

 

Intended Use

   Intended Amount
Dedicated  to Such Use
 

Repay borrowings outstanding under PCEC’s senior secured credit agreement and second lien credit agreement

   $               

Distribution to equity owners of PCEC

   $    

General corporate purposes

   $    

PCEC maintains a $400 million senior secured credit agreement, which provides for revolving loans and a $60 million second lien term loan. Borrowings under the senior secured credit agreement have a maturity date of August 24, 2012 and bear interest at the applicable LIBOR rate, plus applicable margins ranging from 1.50% to 2.25%, or at a base rate, based upon the greatest of (a) the rate of interest as publicly announced by the administrative agent as its “reference rate” and (b) the federal funds rate plus 0.50%, plus applicable margins ranging from 0.50% to 1.25%. Borrowings under the second lien term loan have a maturity date of February 24, 2013 and bear interest at either (a) the greater of (i) the applicable LIBOR rate and (ii) 3.25%, plus the applicable margin of 6.50%, or (b) a base rate, based upon the greater of (i) the rate of interest as publicly announced by the administrative agent as its “reference rate” and (ii) the federal funds rate plus 0.50%, plus the applicable margin of 5.50%.

As of September 30, 2011, total borrowings under PCEC’s senior secured credit agreement were $94.0 million at a weighted average interest rate of approximately 2.04% for the third quarter of 2011. As of September 30, 2011, PCEC had $30.0 million outstanding under its second lien term loan at a weighted average interest rate of approximately 8.75% for the third quarter of 2011.

 

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PACIFIC COAST ENERGY COMPANY LP

PCEC is a privately held Delaware limited partnership formed on June 15, 2004 as BreitBurn Energy Company, L.P. to engage in the production and development of oil and natural gas from properties located in California.

The Underlying Properties were acquired through various transactions prior to 2005 and are located in the Santa Maria and Los Angeles Basins in California. After giving pro forma effect to the conveyances of the Net Profits Interests to the trust, the offering of the trust units contemplated by this prospectus and the application of the net proceeds as described in “Use of Proceeds,” as of September 30, 2011, PCEC would have had total assets of $484.0 million and total liabilities of $36.1 million. For an explanation of the pro forma adjustments, please read “Financial Statements of Pacific Coast Energy Company LP—Unaudited Pro Forma Financial Statements—Introduction.”

As of December 31, 2010, PCEC held interests in approximately 265 gross (204 net) producing wells, and had proved reserves of approximately 19.3 MBoe.

The trust units do not represent interests in, or obligations of, PCEC.

Selected Historical, Unaudited and Pro Forma Financial Data of PCEC

The selected historical audited financial data of PCEC as of December 31, 2010 and 2009 and for the years in the two-year period ended December 31, 2010 and the period from August 26, 2008 to December 31, 2008 have been derived from PCEC’s audited financial statements. The selected historical audited financial data for the period from January 1, 2008 to August 25, 2008 and for the years ended December 31, 2007 and 2006 have been derived from PCEC’s predecessor’s audited financial statements. The selected historical unaudited interim financial data of PCEC as of September 30, 2011 and 2010 and for the nine-month periods ended September 30, 2011 and 2010 have been derived from PCEC’s unaudited interim financial statements. The unaudited interim financial statements were prepared on a basis consistent with the audited statements and, in the opinion of PCEC’s management, include all adjustments (consisting only of normal recurring adjustments) necessary to state fairly the results of PCEC for the periods presented.

The selected unaudited pro forma financial data as of and for the nine months ended September 30, 2011 and for the year ended December 31, 2010 has been derived from the unaudited pro forma financial statements of PCEC included elsewhere in this prospectus. The pro forma data has been prepared as if the conveyances of the Net Profits Interests and the offer and sale of the trust units and application of the net proceeds therefrom had taken place (i) on September 30, 2011, in the case of the pro forma balance sheet information as of September 30, 2011, and (ii) as of January 1, 2010, in the case of the pro forma statements of earnings for the nine months ended September 30, 2011 and for the year ended December 31, 2010. The selected historical and unaudited pro forma financial data presented below should be read in conjunction with “Information About Pacific Coast Energy Company LP—Management’s Discussion and Analysis of Financial Condition and Results of Operations of PCEC” and the accompanying financial statements and related notes of PCEC included elsewhere in this prospectus.

 

(In thousands)

  PCEC Pro Forma
for the Offering
(Including the
Conveyances of the Net
Profits Interests)
    PCEC          Predecessor  
  Nine Months
Ended
September 30,
2011
    Year
Ended
December 31,
2010
    Nine Months
Ended
September 30,
    Year Ended
December 31,
    August 26
to
December 31,
2008
         January 1
to
August 25,
2008
    Year
Ended
December 31,
 
      2011     2010     2010     2009           2007     2006  
  (Unaudited)     (Unaudited)     (Unaudited)     (Unaudited)                                     

Revenues

  $ 106,370      $ 62,805      $ 114,756      $ 61,737      $ 62,805      $ 6,478      $ 166,934          $ 61,472      $ 47,435      $ 124,033   

Net income (loss)

  $ 59,677      $ (307   $ 57,012      $ 1,697      $ (18,810   $ (90,980   $ 135,842          $ 25,063      $ 2,469      $ 46,077   

Total assets (at period end)

  $ 484,047        $ 428,072      $ 406,795      $ 393,315      $ 398,245      $ 509,405          $ 221,675      $ 212,473      $ 178,920   

Total debt(1) (at period end)

  $        $ 124,000      $ 135,000      $ 142,000      $ 133,000      $ 155,500          $ 13,500      $ 9,500      $ 8,000   

Partners’ equity

  $ 447,953        $ 267,978      $ 244,999      $ 211,445      $ 230,742      $ 322,125          $ 171,726      $ 146,665      $ 120,249   

 

(1) As of September 30, 2011, PCEC had $94.0 million of borrowings under its senior secured credit agreement that is classified as short-term debt.

 

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Management of PCEC

PCEC has no employees, executive officers or directors, and is managed by its general partner, PCEC (GP) LLC, or “PCEC GP,” the executive officers of which are employees of BreitBurn Management Company LLC, or “BreitBurn Management.” PCEC GP is managed by the Board of Representatives of Pacific Coast Energy Holdings LLC, or “PCEH,” the sole member of PCEC GP. Set forth in the table below are the names, ages and titles of the Board of Representatives of PCEH and the executive officers of PCEC GP. In August 2008, PCEH acquired its interest in PCEC by acquiring PCEC’s general and limited partners.

 

Name

  

Age

    

Title

Halbert S. Washburn

     51       Co-Chief Executive Officer and Board Representative

Randall H. Breitenbach

     51       Co-Chief Executive Officer and Board Representative

Mark L. Pease

     55       Executive Vice President and Chief Operating Officer

James G. Jackson

     47       Executive Vice President and Chief Financial Officer

Gregory C. Brown

     60       Executive Vice President and General Counsel

Chris E. Williamson

     54       Vice President Operations

W. Jackson Washburn

     49       Vice President Real Estate

Bruce D. McFarland

     55       Treasurer and Secretary

Lawrence C. Smith

     58       Controller

Howard Hoffen

     48       Board Representative

Gregory D. Myers

     41       Board Representative

V. Frank Pottow

     48       Board Representative

Halbert S. Washburn is a co-founder of PCEC and has been PCEH’s Co-Chief Executive Officer since August 2008 and is a member of the Board of Representatives of PCEH, the sole member of PCEC GP. In addition, Mr. Washburn has been the Chief Executive Officer of BreitBurn GP, LLC, or “BreitBurn GP,” which is the General Partner of BreitBurn Energy Partners L.P., a publicly traded oil and gas partnership, since April 2010. He served as Co-Chief Executive Officer and a Director of BreitBurn GP from March 2006 until April 2010 and was the Chairman of the Board from July 2008 to April 2010. In December 2011, he was re-appointed to the Board of BreitBurn GP. Mr. Washburn is the brother of W. Jackson Washburn, PCEH’s Vice President—Real Estate. Since December 2005, Mr. Washburn has served as a member of the Board of Directors and the audit and compensation committees of Rentech, Inc., a publicly traded alternative fuels company, and since June 2011, has served as the Chairman of the Rentech, Inc. Board. Since July 2011, Mr. Washburn has also served as a Director of Rentech Nitrogen GP, LLC, the general partner of Rentech Nitrogen Partners, L.P., a publicly traded limited partnership involved in the production of nitrogen fertilizer. He has been a member of the California Independent Petroleum Association since 1995 and served as Chairman of the executive committee of the Board of Directors from 2008 to 2010. He has also served as a board member, including Chairman of the Board of Directors, of the Stanford University Petroleum Investments Committee. Mr. Washburn holds a B.S. degree in Petroleum Engineering from Stanford University.

Mr. Washburn has a distinguished career as an executive in the oil and gas industry. His more than 25 years of management experience in the oil and gas industry provides Mr. Washburn with a keen understanding of PCEC’s operations and an in-depth knowledge of its industry. Mr. Washburn’s experience serving on boards of directors of both public and private companies allows him to provide PCEH’s Board of Representatives with a variety of perspectives on corporate governance and other issues.

Randall H. Breitenbach is a co-founder of PCEC and has been PCEH’s Co-Chief Executive Officer since August 2008 and is a member and the Chairman of the Board of Representatives of PCEH, the sole member of PCEC GP. He also served as the Co-Chief Executive Officer of PCEC GP since March 2006. In addition, Mr. Breitenbach has been the President of BreitBurn GP since April 2010 and from March 2006 until April 2010, he served as Co-Chief Executive Officer and a Director of BreitBurn GP. In December, 2011, he was re-appointed to the Board of BreitBurn GP. Mr. Breitenbach currently serves as a Trustee and is Chairman of the

 

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governance and nominating committee for Hotchkis and Wiley Funds, which is a mutual funds company. He has also served as a board member, including Chairman of the Board of Directors, of the Stanford University Petroleum Investments Committee. Mr. Breitenbach holds both a B.S and M.S. degree in Petroleum Engineering from Stanford University and an M.B.A. from Harvard Business School.

Mr. Breitenbach has a distinguished career as an executive in the oil and gas industry. His more than 25 years of management experience in the oil and gas industry provides Mr. Breitenbach with a keen understanding of PCEC’s operations and an in-depth knowledge of its industry. Mr. Breitenbach’s experience serving on boards of directors of both public and private companies allows him to provide PCEH’s Board of Representatives with a variety of perspectives on corporate governance and other issues.

Mark L. Pease has been PCEH’s Chief Operating Officer since August 2008. Mr. Pease has been the Chief Operating Officer and an Executive Vice President of BreitBurn GP since December 2007. Prior to joining BreitBurn GP, Mr. Pease served as Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation, an international and domestic oil and natural gas exploration and production company, or “Anadarko.” Mr. Pease joined Anadarko in 1979 as an engineer, and served as Senior Vice President, North America from 2004 to 2006 and as Vice President, U.S. Onshore and Offshore from 2002 to 2004. Mr. Pease obtained a B.S. in Petroleum Engineering from the Colorado School of Mines.

James G. Jackson has been PCEH’s Chief Financial Officer since August 2008. Mr. Jackson has also served as the Chief Financial Officer of BreitBurn GP since July 2006 and as an Executive Vice President since October 2007. Since June 2011, Mr. Jackson has served as a member of the Board of Directors of Niska Gas Storage Partners LLC, a publicly traded master limited partnership that owns and operates natural gas storage assets in North America. Before joining BreitBurn GP, Mr. Jackson served as Managing Director of the Global Markets and Investment Banking Group for Merrill Lynch & Co., a global financial management and investment banking firm. Mr. Jackson joined Merrill Lynch in 1992 and was elected Managing Director in 2001. Previously, Mr. Jackson was a Financial Analyst with Morgan Stanley & Co. from 1986 to 1989 and was an Associate in the Mergers and Acquisitions Group of the Long-Term Credit Bank of Japan from 1989 to 1990. Mr. Jackson obtained a B.S. in Business Administration from Georgetown University and an M.B.A. from the Stanford Graduate School of Business.

Gregory C. Brown has been PCEH’s General Counsel and an Executive Vice President since August 2008. Mr. Brown joined BreitBurn GP in December 2006 and currently serves as its General Counsel and Executive Vice President. Before joining BreitBurn GP Mr. Brown was a partner at Bright and Brown, a law firm specializing in energy and environmental law that he co-founded in 1981. Mr. Brown earned a B.A. degree from George Washington University, with Honors, Phi Beta Kappa, and a J.D. from the University of California, Los Angeles. Mr. Brown was Mayor and has served on the City Council of the City of La Canada Flintridge from 2003 to 2011.

Chris E. Williamson has been PCEH’s Vice President of Operations since August 2008. Mr. Williamson has also served as a Senior Vice President of BreitBurn GP since January 2008 and previously served as Vice President of Operations since March 2006. Before joining BreitBurn GP, Mr. Williamson worked for five years as a petroleum engineer for Macpherson Oil Company. Prior to his position with Macpherson, Mr. Williamson worked at Shell Oil Company for eight years holding various positions in Engineering and Operations. Mr. Williamson holds a B.S. in Chemical Engineering from Purdue University.

W. Jackson Washburn has been PCEH’s Vice President of Real Estate since August 2008. Mr. Washburn has served as the Senior Vice President—Business Development of BreitBurn GP since April 2009 and previously served as Vice President—Business Development since August 2007. Mr. Washburn is the brother of Halbert S. Washburn, PCEH’s Co-Chief Executive Officer. Since joining PCEC’s predecessor in 1992, Mr. Washburn has served in a variety of capacities, and has served as President of PCEC Land Company, LLC, a subsidiary of PCEC, since 2000. Mr. Washburn obtained a B.A. in Psychology from Wake Forest University.

 

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Bruce D. McFarland has been PCEH’s Treasurer since August 2008. Mr. McFarland has served as the Vice President and Treasurer of BreitBurn GP since March 2006 and as a Vice President since April 2009. Mr. McFarland previously served as the Chief Financial Officer of BreitBurn GP from March 2006 through June 2006. Since joining PCEC’s predecessor in 1994, Mr. McFarland served as Controller and Treasurer for more than five years. Before joining PCEC’s predecessor, Mr. McFarland served as Division Controller of IT Corporation and worked at PriceWaterhouseCoopers as a Certified Public Accountant. Mr. McFarland obtained a B.S. in Civil Engineering from the University of Florida and an M.B.A. from the University of California, Los Angeles.

Lawrence C. Smith has been PCEH’s Controller since August 2008. Mr. Smith has also served as the Controller of BreitBurn GP since June 2006 and as a Vice President since April 2009. Before joining BreitBurn GP, Mr. Smith served as the Corporate Accounting Compliance and Implementation Manager of Unocal Corporation, which was an oil and natural gas production and exploration development company, or “Unocal,” from 2000 through May 2006. Mr. Smith worked at Unocal from 1981 through May 2006 and held various managerial positions in Unocal’s accounting and finance organizations. Mr. Smith obtained a B.B.A. in Accounting from the University of Houston, an M.B.A. from the University of California, Los Angeles, and is a Certified Public Accountant.

Howard Hoffen has been a member of the Board of Representatives of PCEH since August 2008. Mr. Hoffen has been the Chairman and Chief Executive Officer of Metalmark Capital LLC, or “Metalmark,” since its formation in 2004. Prior to joining Metalmark, from 2001 to 2004, he was the Chairman and CEO of Morgan Stanley Capital Partners and a Managing Director of Morgan Stanley & Co., since 1997. Additionally, Mr. Hoffen serves as a Director of EnerSys, Union Drilling and several private companies. Mr. Hoffen received a B.S. from Columbia University and an M.B.A from Harvard Business School.

PCEC believes that Mr. Hoffen’s many years of investing experience, as well as his in-depth knowledge of the oil and gas industry generally, and PCEC in particular, provide him with the necessary skills to be a member of the Board of Representatives of PCEC.

Gregory D. Myers has been a member of the Board of Representatives of PCEH since August 2008. Mr. Myers is a Managing Director at Metalmark and was a founding member in 2004. From 1998 to 2004, Mr. Myers was a senior investment professional at Morgan Stanley Capital Partners. Mr. Myers also serves as a Director of Union Drilling and several private companies. Mr. Myers received a B.S. and B.A. from The University of Pennsylvania and an M.B.A. from Harvard Business School.

PCEC believes that Mr. Myers’ many years of investing experience, as well as his in-depth knowledge of the oil and gas industry generally, and PCEC in particular, provide him with the necessary skills to be a member of the Board of Representatives of PCEC.

V. Frank Pottow has been a member of the Board of Representatives of PCEH since August 2008. Since 2009, Mr. Pottow has been a Managing Director and co-founder of GCP Capital Partners, LLC. From 2002 to 2009 Mr. Pottow was a Managing Director and member of the investment committee of Greenhill Capital Partners, LLC, the global merchant banking business of Greenhill & Co., Inc. From 1997 to 2002, he was a co-founder and Managing Director of SG Capital Partners. Additionally, Mr. Pottow was a Principal of Odyssey Partners, L.P. from 1992 to 2002. Mr. Pottow also serves as a board member of several private companies. Mr. Pottow obtained a B.S. from The Wharton School of The University of Pennsylvania and received an M.B.A. from Harvard Business School.

PCEC believes that Mr. Pottow’s many years of investing experience, as well as his in-depth knowledge of the oil and gas industry generally, and PCEC in particular, provide him with the necessary skills to be a member of the Board of Representatives of PCEC.

 

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Beneficial Ownership of PCEC

The following table sets forth, as of November 30, 2011, the beneficial ownership of limited partner interests of PCEC held by:

 

   

each person who beneficially owns 5% or more of the outstanding limited partner interests in PCEC;

 

   

each named executive officer of PCEC GP and member of the Board of Representatives of PCEH; and

 

   

all executive officers of PCEC GP and members of the Board of Representatives of PCEH as a group.

Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all limited partner interests of PCEC shown as beneficially owned by them and their address is 515 South Flower Street, Suite 4800, Los Angeles, California 90071.

 

Name of Beneficial Owner

   Percentage  of
Limited
Partner
Interests

Beneficially
Owned
 

PCEC (LP) LLC(1)

     100

Halbert S. Washburn

       

Randall H. Breitenbach

       

Mark L. Pease

       

James G. Jackson

       

Gregory C. Brown

       

Howard Hoffen

       

Gregory D. Myers

       

V. Frank Pottow

       

Board Representatives and executive officers of PCEC GP as a group (12 persons)

       

 

(1) PCEC (LP) LLC is wholly owned by PCEH, which is owned by Metalmark Capital Partners, GCP Capital Partners, LLC, Wells Fargo Central Capital Pacific Holdings, Inc. and certain members of PCEC GP’s senior management. As of November 30, 2011, the beneficial ownership of limited liability company interests of PCEH is as follows:

 

Name of Beneficial Owner

   Percentage  of
Membership
Interests

Beneficially
Owned
 

Metalmark BreitBurn Holdings LLC

     51.2

Greenhill Capital Partners, LLC

     38.4

Wells Fargo Central Capital Pacific Holdings, Inc.

     2.6

BreitBurn Energy Corporation(a)

     6.5

Halbert S. Washburn(b)

     6.5

Randall H. Breitenbach(b)

     6.5

Mark L. Pease

     0.2

James G. Jackson

     0.3

Gregory C. Brown

     0.2

Board Representatives and executive officers of PCEC GP as a group (12 persons)

     7.8

 

(a) Messrs. Washburn and Breitenbach collectively own 100% of the outstanding shares of BreitBurn Energy Corporation.
(b) Includes interests beneficially owned by BreitBurn Energy Corporation.

 

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Beneficial Ownership of Pacific Coast Oil Trust

The following table sets forth the beneficial ownership of trust units of the trust that will be outstanding after giving effect to the consummation of this offering, assuming no exercise of the underwriters’ option to purchase additional trust units, and held, directly or indirectly, by each person who will then beneficially own 5% or more of the outstanding trust units.

 

Name of Beneficial Owner

   Class of
Securities
     Percentage  of
Ownership
 

PCEC

     Trust Units             

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Registration Rights Agreement

The trust will enter into a registration rights agreement with PCEC in connection with PCEC’s contribution to the trust of the Net Profits Interests. Under the registration rights agreement, the trust will agree, for the benefit of PCEC and any transferee of PCEC’s trust units, to register the trust units they hold. In connection with the preparation and filing of any registration statement, PCEC will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust. Any underwriting discounts and commissions will be borne by the seller of the trust units. Please read “Trust Units Eligible for Future Sale—Registration Rights.”

Operating and Services Agreement

In connection with the closing of this offering, the trust will enter into an operating and services agreement with PCEC pursuant to which PCEC will provide the trust with certain operating and informational services relating to the Net Profits Interests in exchange for a monthly fee. The PCEC operating and services fee will be charged monthly in an amount equal to $1.00 per Boe of production, which fee will change on an annual basis commencing on April 1, 2013, based on changes to the CPI. The PCEC operating and services fee is expected to be $86,250 per month for the twelve months ending March 31, 2013. The PCEC operating and services agreement will terminate upon the termination of the Net Profits Interests unless earlier terminated by mutual agreement of the trustee and PCEC.

 

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THE TRUST

The trust is a statutory trust created under the Delaware Statutory Trust Act on January 3, 2012. The business and affairs of the trust will be managed by The Bank of New York Mellon Trust Company, N.A., as trustee. PCEC has no ability to manage or influence the operations of the trust. In addition, Wilmington Trust, National Association will act as Delaware trustee of the trust. The Delaware trustee will have only minimal duties as are necessary to satisfy the requirement of the Delaware Statutory Trust Act that the trust have at least one trustee who has its principal place of business in Delaware. In connection with the closing of this offering, PCEC will contribute the Net Profits Interests to the trust in exchange for              newly issued trust units. PCEC will make its first payment to the trust pursuant to the Net Profits Interests in June 2012.

The trustee can authorize the trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the trust. The trustee may authorize the trust to borrow from the trustee as a lender provided the terms of the loan are fair to the trust unitholders. The trustee may also deposit funds awaiting distribution in an account with itself, which may be non-interest bearing, and make other short-term investments with the funds distributed to the trust. The trustee has no current plans to authorize the trust to borrow money.

The trust will pay the trustee and Delaware trustee an administrative fee of $200,000 and $2,000 per year, respectively. The trust will also incur legal, accounting, tax, advisory and engineering fees, printing costs and other administrative and out-of-pocket expenses that are deducted by the trust before distributions are made to trust unitholders, including the monthly PCEC operating and services fee described below. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees.

In connection with the closing of this offering, the trust will enter into an operating and services agreement with PCEC pursuant to which PCEC will provide the trust with certain operating and informational services relating to the Net Profits Interests in exchange for a monthly fee. Please read “Certain Relationships and Related Party Transactions—Operating and Services Agreement.” The trust’s general and administrative expenses are expected to be $850,000 for the twelve months ending March 31, 2013. The PCEC operating and services fee will be an amount equal to $1.00 per Boe of production, and is expected to be approximately $1,035,000 for the twelve months ending March 31, 2013. The PCEC operating and services fee will change on an annual basis commencing on April 1, 2013, based on changes to the CPI.

The trust will dissolve upon the earliest to occur of the following: (1) the trust, upon the approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interests, (2) the annual cash available for distribution to the trust is less than $2.0 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding trust units vote in favor of dissolution or (4) the trust is judicially dissolved.

 

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PROJECTED CASH DISTRIBUTIONS

Immediately prior to the closing of this offering, PCEC will create the Net Profits Interests through conveyances to the trust of net profits interests carved from PCEC’s interests in the Underlying Properties located in California. The Net Profits Interests will entitle the trust to receive 80% of the net profits from the sale of oil and natural gas production from the Developed Properties and 25% of the net profits from the sale of oil and natural gas production from the Remaining Properties.

The amount of trust revenues and cash distributions to trust unitholders will depend on, among other things:

 

   

oil and natural gas sales prices;

 

   

the volume of oil and natural gas produced and sold attributable to the Underlying Properties;

 

   

the payments made or received by PCEC pursuant to any commodity derivative contracts;

 

   

direct operating expenses;

 

   

development expenses; and

 

   

administrative expenses of the trust.

PCEC does not as a matter of course make public projections as to future sales, earnings or other results. However, the management of PCEC has prepared the projected financial information set forth below to present the projected cash distributions to the holders of the trust units based on the estimates and hypothetical assumptions described below. The accompanying projected financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to projected financial information. More specifically, such information omits items that are not relevant to the trust.

In the view of PCEC’s management, the accompanying unaudited projected financial information was prepared on a reasonable basis and reflects the best currently available estimates and judgments of PCEC related to oil and natural gas production, operating expenses and development expenses, settlement of commodity derivative contracts and other general and administrative expenses based on:

 

   

the oil and natural gas production estimates for the twelve months ending March 31, 2013 contained in the reserve reports;

 

   

estimated direct operating expenses and development expenses for the twelve months ending March 31, 2013 contained in the reserve reports;

 

   

projected payments made or received pursuant to the commodity derivative contracts for the twelve months ending March 31, 2013;

 

   

estimated trust general and administrative expenses of $850,000 for the twelve months ending March 31, 2013; and

 

   

an operating and services fee of approximately $1,027,000 for the Developed Properties payable to PCEC for the twelve months ending March 31, 2013.

The projected financial information was based on the hypothetical assumption that prices for oil (WTI) and natural gas (Henry Hub) remain constant at $103.00 per Bbl of oil and $3.50 per MMBtu of natural gas during the twelve-month projection period. Actual prices paid for oil and natural gas expected to be produced from the Underlying Properties during the twelve months ending March 31, 2013 will likely differ from these hypothetical prices due to fluctuations in the prices generally experienced with respect to the production of oil and natural gas and variations in basis differentials. For the twelve months ending March 31, 2013, the monthly average forward NYMEX crude oil (WTI) price per Bbl was approximately $102.07 and the monthly average forward NYMEX natural gas (Henry Hub) price per MMBtu was approximately $3.45.

 

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Please read “—Significant Assumptions Used to Prepare the Projected Cash Distributions,” “Risk Factors—Prices of oil and natural gas fluctuate, and changes in prices could reduce proceeds to the trust and cash distributions to trust unitholders” and “Risk Factors—A delay in the East Coyote and Sawtelle Reversion will result in lower distributions to unitholders than those projected, which would continue until the reversion occurs.”

Neither PricewaterhouseCoopers LLP nor any other independent accountant has examined, compiled or performed any procedures with respect to the accompanying projected financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The reports of PricewaterhouseCoopers LLP included in this prospectus relate to the trust, PCEC and PCEC’s predecessor historical financial information. They do not extend to the projected financial information and should not be read to do so.

The projections and estimates and the hypothetical assumptions on which they are based are subject to significant uncertainties, many of which are beyond the control of PCEC or the trust. Actual cash distributions to trust unitholders, therefore, could vary significantly based upon events or conditions occurring that are different from the events or conditions assumed to occur for purposes of these projections. Cash distributions to trust unitholders will be particularly sensitive to fluctuations in oil and natural gas prices. Please read “Risk Factors—Prices of oil and natural gas fluctuate, and changes in prices could reduce proceeds to the trust and cash distributions to trust unitholders.” As a result of typical production declines for oil and natural gas properties, production estimates generally decrease from year to year, and the projected cash distributions shown in the table below are not necessarily indicative of distributions for future years. Please read “—Sensitivity of Projected Cash Distributions to Oil Production and Prices” below, which shows projected effects on cash distributions from hypothetical changes in oil production and prices. Because payments to the trust will be generated by depleting assets and the trust has a finite life with the production from the Underlying Properties diminishing over time, a portion of each distribution will represent, in effect, a return of your original investment. Please read “Risk Factors—The reserves attributable to the Underlying Properties are depleting assets and production from those reserves may diminish over time. Furthermore, the trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the trust and cash distributions to trust unitholders may decrease over time.”

The following table presents a calculation of forecasted cash distributions to holders of trust units for the twelve months ending May 31, 2013, which was prepared by PCEC based on the assumptions that are described below in “—Significant Assumptions Used to Prepare the Projected Cash Distributions.” The following table represents amounts associated with the Developed Properties for the projection period but does not include amounts associated with the Remaining Properties because the costs and development expenses associated with such properties exceed revenues associated with such properties for the projection period.

 

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Projected Cash Distributions to Trust Unitholders

   Projections for the Twelve
Months Ending
May 31, 2013
 
    

(In thousands,

except per unit data)

 

Underlying Properties sales volumes, net to the trust(1):

  

Oil (MBbl)

     995.3   

Natural gas (MMcf)

     189.6   
  

 

 

 

Total sales (MBoe)

     1,026.9   

Daily production (Boe)

     2,813.3   

Commodity prices(2):

  

Oil (per Bbl)

   $ 103.00   

Natural gas (per MMBtu)

   $ 3.50   

Assumed realized sales prices(3):

  

Oil (per Bbl)

   $ 97.31   

Natural gas (per Mcf)

   $ 2.85   

Net profits, net to the trust:

  

Gross profits(4):

  

Oil sales

   $ 96,853   

Natural gas sales

     540   
  

 

 

 

Total

   $ 97,393   

Costs, net to the trust(5):

  

Direct operating expenses:

  

Lease operating expenses

   $ 29,204   

Production and other taxes

     3,200   

Development expenses(6)

     5,470   
  

 

 

 

Total

   $ 37,874   

Settlement of commodity derivative contracts, net to the trust(7)

       

PCEC operating and services fee(8)

     (1,027
  

 

 

 

Net profits to trust from Net Profits Interests

   $ 58,492   

Trust general and administrative expenses(9)

     (850
  

 

 

 

Cash available for distribution by the trust

   $ 57,642   
  

 

 

 

Cash distribution per trust unit (assumes              units)

   $     
  

 

 

 

 

(1) Sales volumes net to the trust include 80% of sales volumes from the Developed Properties contained in the reserve report for the Underlying Properties.
(2) For a description of the effect of lower crude oil prices on projected cash distributions, please read “—Sensitivity of Projected Cash Distributions to Oil Production and Prices.”
(3) Sales price net of forecasted gravity, quality, transportation, gathering and processing and marketing costs. For more information about the estimates and hypothetical assumptions made in preparing the table above, please read “—Significant Assumptions Used to Prepare the Projected Cash Distributions.”
(4) Represents “gross profits” as described in “Computation of Net Profits.”
(5) Costs net to the trust include 80% of costs from the Developed Properties contained in the reserve report for the Underlying Properties.
(6) Total development expenses expected to be allocated to the Net Profits Interests for the twelve months ending March 31, 2013 are $12.5 million, of which $7.0 million relates to the Remaining Properties.
(7) Reflects net cash impact of settlements of commodity derivative contracts relating to production. Please read “The Underlying Properties—Commodity Derivative Contracts.”

 

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(8) The PCEC operating and services fee relating to production from the Developed Properties will be charged monthly in an amount equal to $1.00 per Boe of production, which fee will change on an annual basis commencing on April 1, 2013, based on changes to the CPI.
(9) Total general and administrative expenses of the trust on an annualized basis for the twelve months ending March 31, 2013 are expected to be $850,000 and will include the annual fees to the trustees, accounting fees, engineering fees, legal fees, printing costs and other expenses properly chargeable to the trust.

Significant Assumptions Used to Prepare the Projected Cash Distributions

Timing of actual distributions. In preparing the projected cash distributions above and sensitivity analysis below, the revenues and expenses of the trust were calculated based on the terms of the conveyances creating the trust’s Net Profits Interests. These calculations are described under “Computation of Net Profits.” It is the intent of the trust to distribute to trust unitholders proceeds received by the trust in the month after the trust receives such funds. Monthly cash distributions will be made to holders of trust units as of the applicable record date (generally the last business day of each calendar month) on or before the 10th business day after the record date. Due to the amount of time it typically takes PCEC to collect payments from its customers, it has been assumed, for purposes of the projections, that cash distributions for each month will include oil and natural gas production from 45 to 75 days prior to the distribution date. The first distribution is expected to be made on or about June 15, 2012, and will include cash received from sales of oil and natural gas production and direct operating and development expenses relating to the month of April 2012.

Production estimates and sales volumes. Production estimates for the twelve months ending March 31, 2013 are based on the reserve report for the Underlying Properties. Net sales from the Underlying Properties for the twelve months ending March 31, 2013 is estimated to be 1,276 MBbls of oil and 237 MMcf of natural gas, of which 1,244 MBbls of oil and 237 MMcf of natural gas are attributable to the Developed Properties and 32 MBbls of oil and 0 MMcf of natural gas are attributable to the Remaining Properties. Net sales for the year ended December 31, 2010 were 1,086 MBbls of oil and 259 MMcf of natural gas. PCEC expects an increase in annual production from the Underlying Properties from 2011 to 2012, as reflected in the reserve report, due to its development drilling.

Oil and natural gas prices. Assumed NYMEX oil (WTI) and natural gas (Henry Hub) prices of $103.00 per Bbl and $3.50 per Mcf differ from the actual price PCEC expects to realize for production attributable to the Underlying Properties. Differentials between published oil and natural gas prices and the prices actually received for the oil and natural gas production may vary significantly due to market conditions, transportation, gathering and processing costs, quality of production and other factors.

In the above table, an average of $5.69 per Bbl and $0.65 per Mcf is deducted from the assumed crude oil (WTI) and natural gas (Henry Hub) prices, respectively, to reflect these differentials. These differences are based on PCEC’s estimate of the average difference between the NYMEX published price of crude oil (WTI) and natural gas (Henry Hub) and the price to be received by PCEC for production attributable to the Underlying Properties during the twelve months ending March 31, 2013. Assumed realized oil and natural gas prices appearing in this prospectus have been adjusted for these differentials.

The differentials to published oil and natural gas prices applied in the above projected cash distribution estimate are based upon an analysis by PCEC of the historic price differentials for production from the Underlying Properties with consideration given to gravity, quality and transportation and marketing costs that may affect these differentials. There is no assurance that these assumed differentials will occur.

When oil and natural gas prices decline, PCEC may elect to reduce or completely suspend production. No adjustments have been made to estimated production during the twelve months ending March 31, 2013 to reflect potential reductions or suspensions of production.

Settlement of Commodity Derivative Contracts. PCEC intends to enter into crude oil derivative contracts with unaffiliated third parties in order to mitigate the risk of potentially falling crude oil prices through 2013. The

 

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trust will not bear any hedge settlement costs paid by PCEC, or be entitled to any hedge payments received by PCEC, for periods on or prior to April 2012. For more information, see “The Underlying Properties—Commodity Derivative Contracts.”

Direct Operating Expenses. For the twelve months ending March 31, 2013, PCEC estimates lease operating expenses relating to the Developed Properties to be approximately $36.5 million and production and other taxes to be approximately $4.0 million. For the twelve months ending March 31, 2013, PCEC estimates lease operating expenses relating to the Remaining Properties to be approximately $1.4 million and production and other taxes to be approximately $0.1 million. For the year ended December 31, 2010, total lease operating expenses were $33.2 million and property and other taxes were $2.4 million. For a description of direct operating expenses, please read “Computation of Net Profits—Net Profits Interests.”

Development Expenses. For the twelve months ending March 31, 2013, PCEC estimates development expenses incurred relating to the Developed Properties to be approximately $6.8 million. For the twelve months ending March 31, 2013, PCEC estimates development expenses incurred relating to the Remaining Properties to be approximately $28.1 million. For the year ended December 31, 2010, total development expenses incurred were $44.0 million.

Excess Costs on Remaining Properties. Based on the estimates of production, direct operating expenses and development expenses attributable to the Remaining Properties discussed above, the net profits interest relating to the Remaining Properties for the twelve months ending March 31, 2013 is expected to be negative. The excess costs will be borne by PCEC and will be subject to repayment out of future net profits attributable to the Remaining Properties.

PCEC operating and services fee. The trust will be responsible for paying to PCEC a monthly fee for operating and informational services to be performed by PCEC on behalf of the trust relating to the Net Profits Interests. The PCEC operating and services fee relating to the Developed Properties is anticipated to be approximately $1,027,000 for the twelve months ending March 31, 2013. The PCEC operating and services fee relating to the Remaining Properties is anticipated to be approximately $8,000 for the twelve months ending March 31, 2013. Since the net profits interest relating to the Remaining Properties for the twelve months ending March 31, 2013 is expected to be negative, the PCEC operating and services fee will not be paid to the trust but will be treated as excess costs, which will bear interest and be subject to repayment out of future net profits attributable to the Remaining Properties. The operating and services fee payable to PCEC is an amount equal to $1.00 per Boe of production and will change on an annual basis commencing on April 1, 2013, based on changes to the CPI. Accordingly, the PCEC operating and services fee for subsequent years could be greater or less depending on future events that cannot be predicted. The PCEC operating and services fee will be charged to the trust by PCEC before distributions are made to trust unitholders.

General and administrative expense. The trust will be responsible for paying the annual fees to the trustees, all accounting fees, engineering fees, legal fees, printing costs and other out-of-pocket expenses incurred by or at the direction of the trustee or the Delaware trustee. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. These general and administrative expenses are anticipated to be approximately $850,000 for the twelve months ending March 31, 2013. General and administrative expenses could be greater or less depending on future events that cannot be predicted. Included in the estimates is an annual administrative fee of $200,000 and $2,000 for the trustee and Delaware trustee, respectively. The trust will pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as their acceptance fees in the amount of $10,000 and $1,500, respectively. These costs will be deducted by the trust before distributions are made to trust unitholders. Please read “The Trust.”

 

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Sensitivity of Projected Cash Distributions to Oil Production and Prices

The amount of revenues of the trust and cash distributions to the trust unitholders will be directly dependent on the sales price for oil production sold from the Underlying Properties, the volumes of oil produced attributable to the Underlying Properties, payments made or received under the commodity derivative contracts and variations in direct operating expenses and development expenses.

The table and discussion below set forth sensitivity analyses of annual cash distributions per trust unit for the twelve months ending May 31, 2013, on the assumption that a trust unitholder purchased a trust unit in this offering and held such trust unit until the monthly record date for distributions for May 31, 2013, based upon (1) the assumption that a total of              trust units are issued and outstanding after the closing of the offering made hereby; (2) realization of the production levels estimated in the reserve reports; (3) the hypothetical crude oil prices based upon assumed NYMEX prices; (4) the impact of the commodity derivative contracts entered into by PCEC that relate to production from the Underlying Properties; and (5) other assumptions described above under “—Significant Assumptions Used to Prepare the Projected Cash Distributions.” The hypothetical crude oil prices shown have been chosen solely for illustrative purposes.

The table below is not a projection or forecast of the actual or estimated results from an investment in the trust units. The purpose of the table below is to illustrate the sensitivity of cash distributions to changes in oil pricing (giving effect to the commodity derivative contracts that will be in place during the twelve months ending March 31, 2013). There is no assurance that the hypothetical assumptions described below will actually occur or that NYMEX futures prices will not change by amounts different from those shown in the tables.

It is intended that the trust’s commodity derivative contracts will be in effect only through December 31, 2013, and thus there is likely to be greater fluctuation in cash distributions resulting from fluctuations in the realized oil prices in periods subsequent to the expiration of those contracts. Please read “Risk Factors” for a discussion of various items that could impact production levels and the prices of crude oil.

 

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Sensitivity of Projected Cash Distribution Per Trust Unit

to Changes in NYMEX Futures Pricing

(Period Estimate of April 1, 2012 to March 31, 2013)

 

NYMEX Futures Oil Pricing

($ per Bbl of Oil)

$85.00   $90.00   $95.00   $100.00   $105.00   $110.00   $115.00
$   $   $   $   $   $   $

 

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THE UNDERLYING PROPERTIES

The Underlying Properties consist of producing and non-producing interests in oil units, wells and lands located onshore in California in the Santa Maria Basin, which contains PCEC’s Orcutt properties, and the Los Angeles Basin, which contains PCEC’s West Pico, East Coyote and Sawtelle properties.

The Underlying Properties are located in areas with significant histories of oil and natural gas production. The Santa Maria and Los Angeles Basins are some of California’s longest producing oil regions. Oil reserves in the Santa Maria Basin were discovered in 1901, and the basin has produced over one billion Bbls of oil since that time. Oil reserves in the Los Angeles Basin were discovered in 1892, and the basin has produced over nine billion Bbls of oil since that time. Long producing histories in the Santa Maria and Los Angeles Basins provide for well established production profiles and increased certainty of production estimates.

PCEC acquired its Orcutt properties in the Santa Maria Basin in 2004. PCEC operates approximately 100% of the average daily production associated with these assets and has an average working interest and net revenue interest of approximately 97% and 94%, respectively, in its Orcutt properties. PCEC acquired its West Pico and Sawtelle properties in the Los Angeles Basin in 1993 and acquired its East Coyote properties in 1999 and 2000. PCEC operated approximately 93% of the average daily production associated with the properties in the Los Angeles Basin for the month ended September 30, 2011.

As of September 30, 2011, the Underlying Properties had proved reserves of 33.3 MMBoe. A majority of the proved reserves attributable to the Underlying Properties are proved developed reserves. Proved developed reserves are the most valuable and lowest risk category of reserves because their production requires no significant future development expenses. As of September 30, 2011, approximately 61% of the volumes of the proved reserves associated with the Underlying Properties and 84% of the volumes of the proved reserves associated with the trust were attributed to proved developed reserves. In addition, 100% of the Underlying Properties are held by production or owned in fee. Average net sales (after royalties and other interests) from the Underlying Properties for the twelve months ended September 30, 2011 was approximately 3,252 Boe/d (or 2,602 Boe/d attributable to 80% of proved developed reserves on the Underlying Properties), comprised of approximately 98% oil.

The following table sets forth, as of September 30, 2011, certain estimated proved reserves attributable to the Underlying Properties and the Net Profits Interests, in each case derived from the reserve reports.

 

     Underlying
Properties
     Net Profits
Interests
 
     (In thousands)         

Proved Reserves

     

Oil (MBbls)

     32,680         8,470   

Natural Gas (MMcf)

     3,607         1,107   

Oil Equivalents (MBoe)

     33,281         8,655   

Proved Developed Equivalents (MBoe)

     20,392         7,132   

PCEC’s interests in the Underlying Properties require PCEC to bear its proportionate share of the costs of development and operation of such properties. The Underlying Properties are burdened by non-cost bearing interests owned by third parties consisting primarily of overriding royalty and royalty interests.

 

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Operating Areas

The following table summarizes the estimated proved reserves by operating area attributable to the Underlying Properties as of September 30, 2011 according to the reserve report.

 

Properties

  PCEC
Operated
  Underlying Properties  
    Average Net Daily
Production for the
Month Ended
September 30, 2011
(Boe/d)
    Proved Reserves as of
September 30, 2011(1)
    R/P Ratio as of
September 30, 2011(3)
 
      % Proved
Developed
Reserves
    Total
(MBoe)(2)
    %Oil    

Santa Maria Basin

           

Orcutt, Conventional

  2004 – Present     1,957        100     11,351        100     16.0   

Orcutt, Diatomite

  2005 – Present     649        24     15,289        100     68.6   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Santa Maria Basin Total

      2,606        56     26,640        100     28.6   

Los Angeles Basin

           

West Pico(4)

  1993 – Present     721        66     3,758        85     16.2   

Sawtelle

  1993 – Present     41        100     1,247        98     78.7   

East Coyote

  1999 – Present     23        100     1,636        100     200.8   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Los Angeles Basin Total

      785        81     6,641        91     25.9   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total

      3,391        61     33,281        98     28.0   
   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) In accordance with the rules and regulations promulgated by the SEC, the proved reserves presented above were determined using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from October 1, 2010 through September 30, 2011, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $94.29 per Bbl and a price for natural gas of $4.16 per MMBtu.
(2) Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas are the energy equivalent of one Bbl of oil.
(3) The R/P ratio, or the reserves-to-production ratio, is a measure of the number of years that a specified reserve base could support a fixed amount of production. This ratio is calculated by dividing total estimated proved reserves of the subject properties at the end of a period by annual total production for the prior twelve months. Because production rates naturally decline over time, the R/P ratio is not a useful estimate of how long properties should economically produce.
(4) Consists of the West Pico Unit and includes three Stocker JV wells (a joint venture between PCEC and PXP).

Santa Maria Basin

The Santa Maria Basin consists primarily of oil reserves and prospects in multiple geologic horizons and is one of California’s largest producing oil regions. Conventional production from PCEC’s Orcutt properties is derived from the Monterey, Point Sal and SX Sand formations, which are characterized by long-lived reserves. In addition, the Diatomite and Careaga formations, located at depths less than 900 feet below the surface, provide access to unconventional oil reserves. The portion of the Underlying Properties located in the Orcutt oilfield consists of 3,880 gross (3,580 net) acres.

 

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The following table sets forth the productive zones, recovery method and certain additional information related to the Orcutt properties in the Santa Maria Basin included in the Underlying Properties:

 

Productive Zone

   Recovery
Method
   Working
Interest  (%)
    Net
Revenue

Interest  (%)
    Original
Oil in
Place
(MMBoe)(1)
     Cumulative
Production
(MMBoe)
 

Monterey / Point Sal

   Waterflood      95     90     500         180   

Sx Sand

   Waterflood      100     100     30         0.9   

Diatomite

   Cyclic steam flood      100     100     350         0.5   

Careaga

   Collection      100     100     20         0.2   

 

(1) OOIP is not an indication of the quantity of oil that is likely to be produced or of proved, probable or possible reserves, but rather an indication of the estimated size of a reservoir. It is not possible to measure OOIP in an exact way, and estimating OOIP is inherently uncertain. PCEC’s internal petroleum engineers have estimated OOIP based on their subjective analysis of geological and other relevant data applicable to the Underlying Properties, taking into account many factors and assumptions, some of which may be incorrect. Changes in these factors and assumptions could materially alter the estimates of OOIP.

Orcutt Conventional

The Orcutt oilfield was discovered in 1901 and has produced continuously since that time. Initial production from the Orcutt oilfield came from the Monterey and Point Sal formations, which are located at depths between 3,000 and 4,500 feet below the surface. The Monterey formation in the Orcutt oilfield is a fractured dolomitic shale that is highly productive. The Point Sal formation is a shallow marine deposited turbidite sandstone that is also highly productive. Oil recovery from these formations is enhanced by waterflood injection. The OOIP in the Monterey and Point Sal was approximately 500 MMBoe. Cumulative production from the Monterey and Point Sal is approximately 180 MMBoe. Beginning in 2005 the SX formation underlying PCEC’s Orcutt properties was developed. The SX formation is a silty sandstone at depths between 1,000 and 1,100 feet below the surface. The OOIP in the SX formation was approximately 30 MMBoe. Cumulative production from the SX formation since 2005 is approximately 0.9 MMBoe. A waterflood was initiated for the SX formation in 2009 to maintain reservoir pressure. The producing wells are all artificially lifted with rod pumps and electric submersible pumps. There are currently 123 Monterey, Point Sal and SX formation producing wells, and 58 waterflood injection wells on PCEC’s conventional Orcutt properties. PCEC has operated its Orcutt properties for over seven years. PCEC operates 100% of these assets and has an average working interest of approximately 95%.

Orcutt Diatomite

The Diatomite is a massive silica-rich rock composed of the shells of single-cell organisms that were abundant during certain geologic periods. A Diatomite formation has very high porosity (up to 70%) but very low permeability, meaning fluids will not flow through the rock. Enhanced recovery techniques are used to produce oil from a Diatomite formation. In the 1990s, companies in California began to develop the Diatomite formation utilizing cyclic steam injection to enable oil recovery. These Diatomite formations have very high oil content but are unable to flow oil to a well bore without the cyclic steam injection. The recovery process in the Diatomite consists of injecting steam into each well, letting the steam soak for one to two days, and then producing the well by flowing the hot oil and water to surface. The process is sometimes enhanced by pumping the oil and water for one to four weeks, until the well is ready to be steamed again.

The Diatomite formation in the Orcutt oilfield is a shallow zone that lies approximately 100 to 900 feet below the surface. PCEC began cyclic steam development in 2005 and was producing 49 Diatomite wells using the process described above as of September 30, 2011. PCEC began a project expansion in 2011 to increase the total Diatomite project to 96 wells.

 

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PCEC has targeted the Diatomite formation at depths greater than 400 feet below the surface for development. The Diatomite development area, which covers 750 acres within PCEC’s Orcutt properties, had OOIP of approximately 350 MMBoe at depths greater than 400 feet. PCEC has developed approximately 30 acres to date, and produced over 500 MBoe from the Diatomite oilfield. Ultimate recovery from the Diatomite formation in two analogous fields was estimated by the operator to be as much as 26% of the OOIP.

Careaga formation

Overlying the Diatomite formation in the Orcutt oilfield is the Careaga sandstone reservoir. The Careaga outcrops at the surface in some locations and extends to depths up to 150 feet below the surface. This reservoir contains very heavy oil (11 degree API) that can flow to the surface through seeps. PCEC is collecting the Careaga oil that flows to the surface in containers utilizing a French drain system to gather the oil. PCEC is producing approximately 140 Bbls/d of the Careaga oil that is pumped from the containers and sold with the rest of its crude oil production. The OOIP in the Careaga formation was approximately 20 MMBoe. Cumulative production from the Careaga formation is approximately 200 MBoe.

Los Angeles Basin

Similar to the Santa Maria Basin, the Los Angeles Basin is characterized by its mature oilfields with long production histories that have produced more than nine billion Bbls of oil since its discovery in 1892. The Underlying Properties in the Los Angeles Basin consist of the West Pico, Sawtelle and East Coyote properties. These properties are characterized by their long-lived reserves with well established, predictable production profiles and low decline rates. The portion of the Underlying Properties located in the Los Angeles Basin consists of 2,106 gross (1,049 net) acres after giving effect to the East Coyote and Sawtelle Reversion. Prior to the East Coyote and Sawtelle Reversion the portion of the Underlying Properties located in the Los Angeles Basin consisted of 500 net acres.

The following table sets forth the recovery method and certain additional information about the oilfields in the Los Angeles Basin included in the Underlying Properties:

 

Field

   Operator      Recovery
Method
     Working
Interest  (%)
     Net Revenue
Interest (%)
     Original
Oil in
Place
(MMBoe)(1)
     Cumulative
Production
(MMBoe)
 

West Pico(2)

     PCEC         Waterflood         98.0         84.0         203         70   

Sawtelle(3)

     PCEC         Waterflood         37.6         27.5 - 29.8         92         19   

East Coyote(3)

     PCEC         Waterflood         37.6         34.8         400         106   

 

(1) OOIP is not an indication of the quantity of oil that is likely to be produced or of proved, probable or possible reserves, but rather an indication of the estimated size of a reservoir. It is not possible to measure OOIP in an exact way, and estimating OOIP is inherently uncertain. PCEC’s internal petroleum engineers have estimated OOIP based on their subjective analysis of geological and other relevant data applicable to the Underlying Properties, taking into account many factors and assumptions, some of which may be incorrect. Changes in these factors and assumptions could materially alter the estimates of OOIP.
(2) Located in the East Beverly Hills field and includes the West Pico Unit and three Stocker JV wells (a joint venture between PCEC and PXP).
(3) Gives effect to the East Coyote and Sawtelle Reversion. Prior to the East Coyote and Sawtelle Reversion, PCEC had an average working interest of approximately 5.0% and an average net revenue interest of approximately 3.8% in the East Coyote and Sawtelle properties. Please read “Risk Factors—A delay in the East Coyote and Sawtelle Reversion will result in lower distributions to unitholders than those projected, which would continue until the reversion occurs.”

 

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West Pico

The West Pico Unit was developed from an urban drilling and production site and came on production in 1966. In 2000, PCEC undertook a modernization of its facility and installed a permanently enclosed, electric, soundproof drilling and workover rig that allows for uninterrupted drilling and workover operations despite its close proximity to residential neighborhoods. Production from the West Pico Unit comes from sandstone reservoirs ranging in depths between 4,000 and 7,000 feet below the surface. Oil recovery is enhanced by waterflood injection. The OOIP in the West Pico Unit was approximately 203 MMBoe. Cumulative production from the West Pico Unit is approximately 70 MMBoe. The producing wells in the West Pico Unit are all artificially lifted with rod pumps and electric submersible pumps. There are currently 36 producing wells and 6 waterflood injection wells in the West Pico Unit. Twelve new wells have been drilled from this location since 2003. PCEC has the potential to drill up to 15 additional wells in the West Pico Unit.

West Pico also includes three wells held by the Stocker JV, a joint venture between PCEC and PXP. In accordance with the contractual arrangements with PXP, PXP operates these three wells that were drilled from its facility to three lease line locations between PXP’s and PCEC’s production units. These wells are equally owned by PCEC and PXP, and PCEC receives the production attributable to its properties.

Sawtelle

PCEC’s Sawtelle property is similarly situated in an urban environment. The Sawtelle oilfield was discovered in 1965 and is currently the deepest producing oilfield in the Los Angeles Basin with well depths up to 11,500 feet below the surface. Production at PCEC’s Sawtelle property comes from sandstone reservoirs in three separate pools ranging in depth between 7,500 and 11,500 feet below the surface. Oil recovery is enhanced by waterflood injection in two of the three pools. The OOIP in PCEC’s Sawtelle property was approximately 92 MMBoe. Cumulative production from the Sawtelle property is approximately 19 MMBoe. The producing wells are all artificially lifted with hydraulic pumps, and electric submersible pumps. There are currently 11 producing wells and three waterflood injection wells in PCEC’s Sawtelle property.

East Coyote

The East Coyote oilfield was discovered in 1909. Production at PCEC’s East Coyote property comes from three sandstone formations ranging in depth from 2,000 to 6,000 feet below the surface. The OOIP in PCEC’s East Coyote property was approximately 400 MMBoe. Cumulative production from PCEC’s East Coyote property is approximately 106 MMBoe. The producing wells are all artificially lifted with rod pumps and electric submersible pumps. There are currently 46 producing wells, and 14 waterflood injection wells in PCEC’s East Coyote property.

2012 Capital Budget

For 2012, PCEC has a capital budget of $68.9 million for the Orcutt oilfield in the Santa Maria Basin, of which $54.3 million will be invested in the Orcutt Diatomite properties and $14.6 million will be invested in the conventional Orcutt properties. Of the $54.3 million to be invested in the Orcutt Diatomite properties, $16.3 million will be spent to develop 38 wells at an estimated average cost per well of $430,000, $35.6 million will be spent on facilities and $2.4 million will be spent on workovers, recompletions and test holes. Of the $14.6 million to be invested in the conventional Orcutt properties, $8.1 million will be spent on facilities, $5.4 million will be spent on drilling and $1.1 million will be spent on workovers.

For 2012, PCEC has a capital budget of $11.6 million for the Los Angeles Basin, of which $11.3 million, $0.1 million and $0.2 million will be invested in the West Pico, East Coyote and Sawtelle properties, respectively. Of the $11.6 million to be invested in the Los Angeles Basin, $3.4 million will be spent on drilling, $8.0 million will be spent on facilities and $0.2 million will be spent on artificial lift.

 

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With respect to the Underlying Properties operated by PCEC, PCEC expects, but is not obligated, to implement the foregoing capital expenditures. Any additional incremental revenue received by PCEC from additional production resulting from future capital expenditures could have the effect of increasing future distributions to the trust unitholders. No assurance can be given, however, that any development well will produce in commercial quantities or that the characteristics of any development well will match the characteristics of PCEC’s existing wells or historical drilling success rate.

Operating Data of PCEC

The following table provides oil and natural gas sales volumes, average sales prices, average costs per Boe and capital expenditures relating to the Underlying Properties for the nine months ended September 30, 2011 and 2010 and for the three years in the period ended December 31, 2010.

 

     Nine Months Ended
September 30,
     Year Ended December 31,  
     2011      2010      2010      2009      Combined 2008  
            (Unaudited)                

Operating data:

              

Sales volumes:

              

Oil (MBbls)

     869         817         1,086         1,240         947   

Natural gas (MMcf)

     212         207         259         305         315   

Total sales (MBoe)

     905         851         1,129         1,291         999   

Average sales prices:

              

Oil (per Bbl)

   $ 90.14       $ 68.07       $ 69.99       $ 53.22       $ 86.57   

Natural gas (per Mcf)

     3.87         3.70         3.45         2.72         7.22   

Average costs per Boe:

              

Lease operating expenses

   $ 30.89       $ 28.90       $ 29.37       $ 27.02       $ 33.12   

Production and property taxes

     2.17         1.67         2.08         2.92         1.81   

Capital expenditures (in thousands):

              

Property development costs

   $ 20,576       $ 29,992       $ 44,000       $ 15,852       $ 28,291   

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Please read “Information about Pacific Coast Energy Company LP—Management’s Discussion and Analysis of Financial Condition and Results of Operations of PCEC.”

Commodity Derivative Contracts

To mitigate the negative effects of a possible decline in crude oil prices on distributable income to the trust, PCEC intends to enter into commodity derivative contracts with respect to 50% to 70% of expected crude oil production for 2012 and 2013 from the proved developed reserves attributable to the Underlying Properties in the reserve report. These commodity derivative contracts may include a combination of puts, swaps, and collars to mitigate the risk of price declines to the trust, while still allowing the trust to benefit from increases in oil prices.

 

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Producing Acreage and Well Counts

For the following data, “gross” refers to the total number of wells or acres in which PCEC owns a working interest and “net” refers to gross wells or acres multiplied by the percentage working interest owned by PCEC. All of the acreage comprising the Underlying Properties is held by production. Although many of PCEC’s wells produce both oil and associated natural gas, because a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production, all of PCEC’s wells are classified as oil wells. The Underlying Properties are interests in properties located in the Santa Maria Basin and Los Angeles Basin. The following is a summary of the approximate acreage of the Underlying Properties at December 31, 2010.

 

     Acres  
     Gross      Net  

Santa Maria Basin

     3,880         3,580   

Los Angeles Basin

     2,106         500   
  

 

 

    

 

 

 

Total

     5,986         4,080   
  

 

 

    

 

 

 

The following is a summary of the producing wells on the Underlying Properties as of December 31, 2010:

 

     Oil      Natural Gas  
     Gross  Wells(1)      Net Wells      Gross  Wells(1)      Net Wells  

Santa Maria Basin

     169         163         0         0   

Los Angeles Basin

     96         41         0         0   
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     265         204         0         0   
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) PCEC’s total wells include 262 operated wells and 3 non-operated wells.

The following is a summary of the number of development and exploratory wells drilled on the Underlying Properties during the last three years.

 

     Year Ended December 31,  
     2010      2009      2008  
     Gross      Net      Gross      Net      Gross      Net  

Development Wells:

                 

Productive

     33         33         11         11         17         17   

Dry holes

     0         0         1         1         1         1   

Exploratory Wells:

                 

Productive

     0         0         0         0         0         0   

Dry holes

     5         5         0         0         0         0   

Total:

                 

Productive

     33         33         11         11         17         17   

Dry holes

     5         5         1         1         1         1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     38         38         12         12         18         18   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Reserve Reports

Technologies. The reserve reports were prepared using production performance decline curve analyses to determine the reserves of the Underlying Properties in California. After estimating the reserves of each proved developed property, it was determined that a reasonable level of certainty exists with respect to the reserves which can be expected from any individual undeveloped well in the field. The consistency of reserves attributable to the proved developed wells in California, which cover a wide area, further supports proved undeveloped classification.

 

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Internal controls. Netherland Sewell, the independent petroleum engineering consultant, estimated all of the proved reserve information for the Underlying Properties in this registration statement in accordance with appropriate engineering, geologic and evaluation principles and techniques that are in accordance with practices generally accepted in the petroleum industry, and definitions and guidelines established by the SEC. These reserves estimation methods and techniques are widely taught in university petroleum curricula and throughout the industry’s ongoing training programs. Although these engineering, geologic and evaluation principles and techniques are based upon established scientific concepts, the application of such principles and techniques involves extensive judgment and is subject to changes in existing knowledge and technology, economic conditions and applicable statutory and regulatory provisions. These same industry-wide applied techniques are used in determining estimated reserve quantities. The technical person primarily responsible for overseeing preparation of the reserves estimates and the third party reserve reports is Mark L. Pease, the Executive Vice President and Chief Operating Officer of BreitBurn Management, the company that provides services to PCEC GP, the general partner of PCEC. Mr. Pease received a Bachelor of Science in Petroleum Engineering from the Colorado School of Mines in 1979. Prior to joining PCEC, Mr. Pease was Senior Vice President, E&P Technology & Services for Anadarko Petroleum Corporation. Mr. Pease has over 30 years of experience working in various capacities in the energy industry, including acquisition analysis, reserve estimation, reservoir engineering and operations engineering. Mr. Pease consults with Netherland Sewell during the reserve estimation process to review properties, assumptions and relevant data. Additionally, PCEC’s senior management has reviewed and approved all Netherland Sewell summary reserve reports contained in this prospectus.

The reserves estimates shown herein have been independently evaluated by Netherland Sewell, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. Netherland Sewell was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within Netherland Sewell, the technical persons primarily responsible for preparing the estimates set forth in the Netherland Sewell reserves report incorporated herein are Mr. J. Carter Henson, Jr. and Mr. Mike K. Norton. Mr. Henson has been practicing consulting petroleum engineering at Netherland Sewell since 1989. Mr. Henson is a Licensed Professional Engineer in the State of Texas (No. 73964) and has over 30 years of practical experience in petroleum engineering, with over 22 years experience in the estimation and evaluation of reserves. He graduated from Rice University in 1981 with a Bachelor of Science Degree in Mechanical Engineering. Mr. Norton has been practicing consulting petroleum geology at Netherland Sewell since 1989. Mr. Norton is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441) and has over 33 years of practical experience in petroleum geosciences, with over 25 years experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Netherland Sewell estimated oil and natural gas reserves attributable to PCEC and the Net Profits Interests as of September 30, 2011 and PCEC as of December 31, 2010. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates.

The discounted estimated future net revenues presented below were prepared using the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, without giving effect to any hedge transactions, and were held constant for the life of the properties. This yielded a price for oil of $79.54 per Bbl and a price for natural gas of $4.45 per MMBtu. Oil equivalents in the table are the sum of the Bbls of oil and the Boe of the stated Mcfs of natural gas, calculated on the basis that six Mcfs of natural gas is the energy equivalent of one Bbl of oil. The estimated future net revenues attributable to the Net Profits Interests as of December 31, 2010 are net of the trust’s proportionate share of all

 

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estimated costs deducted from revenue pursuant to the terms of the conveyance creating the Net Profits Interests. Because oil and natural gas prices are influenced by many factors, use of the twelve month unweighted arithmetic average of the first-day-of-the-month price for the period from January 1, 2010 through December 1, 2010, as required by the SEC, may not be the most accurate basis for estimating future revenues of reserve data. Future net cash flows are discounted at an annual rate of 10%. There is no provision for federal income taxes with respect to the future net cash flows attributable to the Underlying Properties or the Net Profits Interests because future net revenues are not subject to taxation at the PCEC or trust level.

Proved reserves of Underlying Properties. The following table sets forth, as of December 31, 2010, certain estimated proved reserves, estimated future net revenues and the discounted present value thereof attributable to the Underlying Properties and have been derived from the reserve report.

 

     Underlying
Properties
    Net
Profits
Interests
 
     (In thousands)  

Proved Reserves

    

Oil (MBbls)

     18,508     

Natural Gas (MMcf)

     4,808     

Oil Equivalents (MBoe)

     19,309     

Future Net Revenues

   $ 1,326,482      $                

Future Production Cost

   $ (766,789   $     

Future Development Cost

   $ (53,424   $     
  

 

 

   

 

 

 

Future Net Cash Flows

   $ 506,269      $     

Standardized Measure of Discounted Future Net Cash Flows

   $ 276,461      $     

As proved reserves are evaluated using only direct costs such as production costs, production taxes, work-over, gathering and processing, transportation and drilling costs, if applicable, and other costs such as general and administrative, depreciation, depletion and amortization, interest and derivative losses are not included, the attribution of proved reserves is not necessarily a sign of future overall corporate profitability.

 

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Changes in Estimated Proved Reserves

The following table summarizes the changes in estimated proved reserves of the Underlying Properties for the periods indicated. The data is presented assuming PCEC owned all the Underlying Properties as of December 31, 2007.

 

     Oil
(MBbls)
    Natural
Gas

(MMcf)
    Oil
Equivalents
(MBoe)
 

Proved Reserves:

      

Balance, January 1, 2008

     22,874        6,464        23,951   

Revisions of prior estimates

     (15,076     (5,962     (16,070

Production

     (947     (315     (999

Balance, December 31, 2008

     6,851        187        6,882   

Revisions of prior estimates

     6,723        3,167        7,251   

Production

     (1,240     (305     (1,291

Balance, December 31, 2009

     12,334        3,049        12,842   

Revisions of prior estimates

     7,260        2,018        7,596   

Production

     (1,086     (259     (1,129

Balance, December 31, 2010

     18,508        4,808        19,309   

Proved Developed Reserves:

      

Balance, December 31, 2008

     6,411        187        6,442   

Balance, December 31, 2009

     11,320        1,475        11,566   

Balance, December 31, 2010

     16,982        2,879        17,462   

Proved Undeveloped Reserves:

      

Balance, December 31, 2008

     440               440   

Balance, December 31, 2009

     1,014        1,574        1,276   

Balance, December 31, 2010

     1,526        1,929        1,847   

During 2008, there were 35 wells drilled on the Underlying Properties, all of which were drilled in the Santa Maria Basin. These 35 wells were drilled at a cost of $16.3 million and resulted in the conversion of 2,793 MBoe of reserves from proved undeveloped to proved developed.

During 2009, there were five wells drilled on the Underlying Properties, all of which were drilled in the Santa Maria Basin. These five wells were drilled at a cost of $3.4 million and resulted in the conversion of 230 MBoe of reserves from proved undeveloped to proved developed.

During 2010, there were three wells drilled on the Underlying Properties, all of which were drilled in the Los Angeles Basin. These three wells were drilled at a cost of $11.8 million and resulted in the conversion of 263 MBoe of reserves from proved undeveloped to proved developed.

Reserve Estimates

PCEC has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.

Changes in Proved Undeveloped Reserves

Santa Maria Basin

In 2010, there were no wells drilled in the Orcutt properties that resulted in conversion of proved undeveloped reserves to proved developed reserves.

 

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Los Angeles Basin

In 2010, three wells were drilled at West Pico at a cost of $11.8 million. This drilling resulted in the conversion of 263 MBoe of proved undeveloped reserves to proved developed reserves.

Development of Proved Undeveloped Reserves

All proved undeveloped locations are scheduled to be spud within the next five years. PCEC does not recognize proved undeveloped reserves beyond five years.

Sale and Abandonment of Underlying Properties

PCEC or any transferee will have the right to abandon its interest in any well or property if it reasonably believes a well or property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, the portion of the Net Profits Interests relating to the abandoned property will be extinguished.

PCEC generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interests, without the consent of the trust unitholders. In addition, PCEC may, without the consent of the trust unitholders, require the trust to release the Net Profits Interests associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior twelve months and provided that the Net Profits Interests covered by such releases cannot exceed, during any twelve month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by PCEC to a non-affiliate of the relevant Underlying Properties, are conditioned upon the trust receiving an amount equal to the fair market value (net of sales costs) to the trust of such Net Profits Interests and will be treated as an offset amount against costs and expenses. PCEC has not identified for sale any of the Underlying Properties.

Marketing and Post-Production Services

Pursuant to the terms of the conveyance creating the Net Profits Interests, PCEC will have the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interests in the Underlying Properties. The terms of the conveyance restrict PCEC from charging any fee for marketing production attributable to the Net Profits Interests other than fees for marketing paid to non-affiliates. Accordingly, a marketing fee will not be deducted (other than fees paid to non-affiliates) in the calculation of the Net Profits Interests’ share of net profits; however, the terms of the conveyances provide that costs and expenses PCEC allocates to marketing production from the Underlying Properties are deducted from the calculation of gross profits. The net profits to the trust from the sales of oil and natural gas production from the Underlying Properties attributable to the Net Profits Interests will be determined based on the same price that PCEC receives for sales of oil and natural gas production attributable to PCEC’s interest in the Underlying Properties. However, in the event that the oil or natural gas is processed, the net profits will receive the same processing upgrade or downgrade as PCEC.

During the year ended December 31, 2010, PCEC sold the oil produced from the Underlying Properties to third-party crude oil purchasers. Oil production from the Underlying Properties is typically transported by pipeline from the field to a gathering facility or refinery. PCEC sells the majority of the oil production from the Underlying Properties under contracts using market sensitive pricing. The price received by PCEC for the oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon delivery location and oil quality. In 2010, ConocoPhillips accounted for 97% of PCEC’s net sales. PCEC does not believe that the loss of ConocoPhillips as a purchaser of crude oil production from the Underlying Properties would have a material impact on the business or operations of PCEC or the Underlying Properties because of the competitive marketing conditions in California.

 

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All natural gas produced by PCEC that is not consumed in its Diatomite production is marketed and sold to third-party purchasers. In all cases, the contract price is based on a percentage of a published regional index price, after adjustments for Btu content, transportation and related charges.

Title to Properties

The properties comprising the Underlying Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens and obligations affect PCEC’s rights to production or the value of production from the Underlying Properties, they have been taken into account in calculating the trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties.

PCEC’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject, in one degree or another, to one or more of the following:

 

   

royalties and other burdens, express and implied, under oil and natural gas leases and other arrangements;

 

   

overriding royalties, production payments and similar interests and other burdens created by PCEC’s predecessors in title;

 

   

a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their title;

 

   

liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate proceedings;

 

   

pooling, unitization and communitization agreements, declarations and orders;

 

   

easements, restrictions, rights-of-way and other matters that commonly affect property;

 

   

conventional rights of reassignment that obligate PCEC to reassign all or part of a property to a third party if PCEC intends to release or abandon such property;

 

   

preferential rights to purchase or similar agreements and required third party consents to assignments or similar agreements;

 

   

obligations or duties affecting the Underlying Properties to any municipality or public authority with respect to any franchise, grant, license or permit, and all applicable laws, rules, regulations and orders of any governmental authority; and

 

   

rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties and also the interests held therein, including PCEC’s interests and the Net Profits Interests.

PCEC believes that the burdens and obligations affecting the properties comprising the Underlying Properties are conventional in the industry for similar properties. PCEC also believes that the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the Net Profits Interests or their value.

In order to give third parties notice of the Net Profits Interests, PCEC will record the conveyance of the Net Profits Interests in California in the real property records in each county in which the Underlying Properties are located, or in such other public records as required under California law to place third parties on notice of the conveyance.

PCEC believes that its title to the Underlying Properties is, and the trust’s title to the Net Profits Interests will be, good and defensible in accordance with standards generally accepted in the oil and gas industry, subject

 

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to such exceptions as are not so material to detract substantially from the use or value of such properties or royalty interests. Under the terms of the conveyance creating the Net Profits Interests, PCEC has provided a special warranty of title with respect to the Net Profits Interests, subject to the burdens and obligations described in this section. Please read “Risk Factors—The trust units may lose value as a result of title deficiencies with respect to the Underlying Properties.”

Competition and Markets

The oil and natural gas industry is highly competitive. PCEC competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than PCEC, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. The trust will be subject to the same competitive conditions as PCEC and other companies in the oil and natural gas industry.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Future price fluctuations for oil and natural gas will directly impact trust distributions, estimates of reserves attributable to the trust’s interests and estimated and actual future net revenues to the trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the trust nor PCEC can make reliable predictions of future oil and natural gas supply and demand, future product prices or the effect of future product prices on the trust.

Environmental Matters and Regulation

General. The oil and natural gas exploration and production operations of PCEC are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose significant obligations on PCEC’s operations, including requirements to:

 

   

obtain permits to conduct regulated activities;

 

   

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

 

   

restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling and production activities;

 

   

initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling pits and plugging of abandoned wells;

 

   

apply specific health and safety criteria addressing worker protection; and

 

   

impose substantial liabilities on PCEC for pollution resulting from PCEC’s operations.

For all of PCEC’s operations, numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often times requiring difficult and costly actions. Failure to comply with environmental laws and regulations may result in the assessment of administrative, civil and criminal sanctions, including monetary penalties, the imposition of joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of PCEC’s operations. Moreover, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The

 

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regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. PCEC believes that it is in substantial compliance with all existing environmental laws and regulations applicable to its current operations and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the trust unitholders. However, the clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could have a material adverse effect on PCEC’s development expenses, results of operations and financial position. PCEC may be unable to pass on those increases to its customers. Moreover, accidental releases or spills may occur in the course of PCEC’s operations, and PCEC cannot assure you that it will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

The following is a summary of certain existing environmental, health and safety laws and regulations, each as amended from time to time, to which PCEC’s business operations are subject.

Hazardous substance and wastes. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. PCEC generates materials in the course of its operations that may be regulated as hazardous substances.

The Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration, production and development of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes, or “E&P Wastes,” now classified as non-hazardous could be classified as hazardous wastes in the future. In September 2010, the Natural Resources Defense Council filed a petition with the EPA to request reconsideration of the exemption of E&P Wastes from regulation as hazardous waste under RCRA (which could also affect E&P Wastes’ regulation under other environmental laws, including CERCLA). Any such change could result in an increase in the costs to manage and dispose of wastes, which could have a material adverse effect on the cash distributions to the trust unitholders. In addition, PCEC generates industrial wastes in the ordinary course of its operations that may be regulated as hazardous wastes.

The real properties upon which PCEC conducts its operations have been used for oil and natural gas exploration and production for many years. Although PCEC may have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of or released on or under the real properties upon which PCEC conducts its operations, or on or under other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, the real properties upon which PCEC conducts its operations may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was

 

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not under PCEC’s control. These real properties and the petroleum hydrocarbons and wastes disposed or released thereon may be subject to CERCLA, RCRA and analogous state laws. Under such laws, PCEC could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.

At the Orcutt Diatomite properties, the cyclic steam flooding technique has the effect of stimulating the release of low-specific-gravity hydrocarbons from the cap rock formation, which manifest at the surface in a series of small “seeps.” PCEC regularly inspects this surface formation for seeps, and notifies appropriate authorities when one is located. PCEC uses a French drain system to contain and collect these hydrocarbons under agency supervision. The hydrocarbons collected from the seeps are marketed along with PCEC’s other production from its Orcutt properties.

Water discharges. The Federal Water Pollution Control Act, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. Spill prevention, control and countermeasure, or “SPCC,” plan requirements imposed under the Clean Water Act require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. The Oil Pollution Act of 1990, as amended, or “OPA,” amends the Clean Water Act and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst case discharge of oil into waters of the United States.

In addition, naturally occurring radioactive material, or “NORM,” is at times brought to the surface in connection with oil and gas production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM.

Air emissions. The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting programs and also impose various monitoring and reporting requirements. These laws and regulations may require PCEC to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. For example, on July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or “VOCs,” and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The proposed rules also would establish specific new requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comments and hold hearings regarding the proposed rules and must take final action on the rules by April 3, 2012. If finalized, these rules could increase the costs of development and production, reducing the profits available to the trust and potentially impairing the economic development of the Underlying Properties. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations.

 

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Climate change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as GHGs, and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. The United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” became effective on February 16, 2005 as a result of these negotiations, but the United States did not ratify the Kyoto Protocol. At the end of 2009, an international conference to develop a successor to the Kyoto Protocol issued a document known as the Copenhagen Accord. Pursuant to the Copenhagen Accord, the United States submitted a greenhouse gas emission reduction target of 17 percent compared to 2005 levels.

Both houses of Congress have actively considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. For example, California enacted AB32, the Global Warming Solutions Act of 2006, which established the first statewide program in the United States to limit GHG emissions and impose penalties for non-compliance. Since then, the California Air Resources Board has taken and plans to take various actions to implement the program, including the approval on December 11, 2008, of an AB32 Scoping Plan summarizing the main GHG-reduction strategies for California. In August 2011, the CARB approved its revised supplemental California Environmental Quality Act, or “CEQA,” analysis in support of the cap and trade regulatory program. In October 2011, the CARB adopted the final cap-and-trade regulation, including a delay in the start of the cap-and-trade rule’s compliance obligations until 2013. The final cap-and-trade system is designed to be in conjunction with the Western Climate Initiative, which currently includes seven states, and four Canadian provinces. Because oil production operations emit GHGs, PCEC’s operations in California are subject to regulations issued under AB32. These regulations increase PCEC’s costs for those operations and adversely affect its operating results. Although it is not possible at this time to predict when Congress may pass climate change legislation, any future federal or state laws that may be adopted to address GHG emissions could require PCEC to incur increased operating costs and could adversely affect demand for the oil and natural gas PCEC produces.

In addition, on December 15, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public heath and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards take effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under PSD and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. In December 2010, the EPA promulgated Federal Implementation Plans to establish GHG permitting under the PSD program in several jurisdictions in which applicable State Implementation Plans did not accommodate the regulation of GHGs. In many other jurisdictions, applicable State Implementation Plans may provide for GHG permitting under the PSD program. In addition, on November 30, 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities will be required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future.

 

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Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact PCEC’s operations. In addition to these regulatory developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase PCEC’s litigation risk for such claims. The adoption of any future regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the equipment and operations of PCEC could require PCEC to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with its operations, and such requirements also could adversely affect demand for the oil and natural gas that PCEC produces.

Legislation or regulations that may be adopted to address climate change could also affect the markets for PCEC’s products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with higher greenhouse gas emitting energy sources, PCEC’s products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. To the extent that its products are competing with lower greenhouse gas emitting energy, PCEC’s products would become less desirable in the market with more stringent limitations on greenhouse gas emissions. PCEC cannot predict with any certainty at this time how these possibilities may affect its operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by PCEC or otherwise cause PCEC to incur significant costs in preparing for or responding to those effects.

National Environmental Policy Act and California Environmental Quality Act. Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended, or “NEPA.” Some of PCEC’s production, most notably from the Sawtelle property, is located on federally-administered land and therefore permits or authorizations issued for this field may be subject to NEPA. NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. This process has the potential to delay the development of oil and natural gas projects.

Similarly, the CEQA imposes similar requirements on California state and local agencies to review environmental impacts from their proposed approvals and to develop and impose mitigation measures appropriate to reduce such impacts to insignificance where feasible. All of the Underlying Properties are located in California and are therefore subject to CEQA to the extent discretionary permits or approvals are required from California state or local agencies. In particular, PCEC’s plan to increase production in the Orcutt Diatomite beyond the currently-permitted wells will require additional permits and approvals from various state, federal and local agencies, in addition to a new review under CEQA, possibly including an environmental impact report. Such a process could take several months or longer, and there can be no assurance that such permits would be timely obtained or on terms and conditions consistent with PCEC’s proposed plan.

Endangered Species Act. The federal Endangered Species Act, or “ESA,” restricts activities that may affect endangered and threatened species or their habitats. The presence of endangered species or designation of previously unidentified endangered or threatened species could cause PCEC to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas, including the obligation to obtain permits from the United States Fish & Wildlife Service or the California Department of Fish & Game with respect to one or more such species. Certain protected species are known to occur on PCEC’s Orcutt and East Coyote properties, and others may yet be found or proposed for protection at one or more of the Underlying Properties. While some of PCEC’s facilities or leased acreage may be located in areas that are or will be designated as habitat for endangered or threatened species, PCEC believes that it is currently in substantial compliance with the ESA.

 

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Employee health and safety. The operations of PCEC are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard 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 operations and that this information be provided to employees, state and local government authorities and citizens. PCEC believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.

 

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COMPUTATION OF NET PROFITS

The provisions of the conveyances governing the computation of net profits are detailed and extensive. The following information summarizes the material information contained in the conveyances related to the computation of net profits. This summary may not contain all information that is important to you. For more detailed provisions concerning the Net Profits Interests, you should read the conveyances. Forms of the conveyances will be filed as exhibits to the registration statement. Please read “Where You Can Find More Information.”

Net Profits Interests

The amounts paid to the trust for each Net Profits Interest are based on, among other things, the definitions of “gross profits” and “net profits” contained in the conveyances and described below. Under the conveyance, net profits are computed monthly. Each calendar month, 80% of the net profits from the sale of oil and natural gas production from the Developed Properties and 25% of the net profits from the sale of oil and natural gas production from the Remaining Properties will be paid to the trust on or before the end of the following month. PCEC will not pay to the trust any interest on the net profits held by PCEC prior to payment to the trust, provided that such payments are timely made. The trustee will make distributions to trust unitholders monthly. Please read “Description of the Trust Units—Distributions and Income Computations.”

“Gross profits” means the aggregate amount received by PCEC that is attributable to sales of oil and natural gas production from the Underlying Properties from and after April 1, 2012 (after deducting the appropriate share of all royalties and any overriding royalties, production payments and other similar charges and other than certain excluded proceeds, as described in the conveyances), including all proceeds and consideration received (i) for advance payments, (ii) under take-or-pay and similar provisions of production sales contracts (when credited against the price for delivery of production) and (iii) under balancing arrangements. Gross profits do not include consideration for the transfer or sale of any Underlying Property by PCEC or any subsequent owner to any new owner, unless the Net Profits Interest in such Underlying Property is released (as is permitted under certain circumstances). Gross profits also do not include any amount for oil or natural gas lost in production or marketing or used by the owner of the Underlying Properties in drilling, production and plant operations.

“Net profits” means gross profits less the following costs, expenses and, where applicable, losses, liabilities and damages all as actually incurred by PCEC from and after April 1, 2012 and attributable to production from the Underlying Properties from and after April 1, 2012 (as such items are reduced by any offset amounts, as described in the conveyances):

 

   

all costs for (i) drilling, development, production and abandonment operations, (ii) all direct labor and other services necessary for drilling, operating, producing and maintaining the Underlying Properties and workovers of any wells located on the Underlying Properties, (iii) treatment, dehydration, compression, separation and transportation, (iv) all materials purchased for use on, or in connection with, any of the Underlying Properties and (v) any other operations with respect to the exploration, development or operation of hydrocarbons from the Underlying Properties;

 

   

all losses, costs, expenses, liabilities and damages with respect to the operation or maintenance of the Underlying Properties for (i) defending, prosecuting, handling, investigating or settling litigation, administrative proceedings, claims, damages, judgments, fines, penalties and other liabilities, (ii) the payment of certain judgments, penalties and other liabilities, (iii) the payment or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying with applicable local, state and federal statutes, ordinances, rules and regulations, (v) tax or royalty audits and (vi) any other loss, cost, expense, liability or damage with respect to the Underlying Properties not paid or reimbursed under insurance;

 

   

all taxes, charges and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate, franchise and like taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying Properties;

 

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all insurance premiums attributable to the ownership or operation of the Underlying Properties for insurance actually carried with respect to the Underlying Properties, or any equipment located on any of the Underlying Properties, or incident to the operation or maintenance of the Underlying Properties;

 

   

all amounts and other consideration for (i) rent and the use of or damage to the surface, (ii) delay rentals, shut-in well payments and similar payments and (iii) fees for renewal, extension, modification, amendment, replacement or supplementation of the leases included in the Underlying Properties;

 

   

all amounts charged by the relevant operator as overhead, administrative or indirect charges specified in the applicable operating agreements or other arrangements covering the Underlying Properties or PCEC’s operations with respect thereto;

 

   

to the extent that PCEC is the operator of certain of the Underlying Properties and there is no operating agreement covering such portion of the Underlying Properties, those overhead, administrative or indirect charges that are allocated by PCEC to such portion of the Underlying Properties;

 

   

if, as a result of the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of hydrocarbons produced from the Underlying Properties, any amounts previously credited to the determination of the net profits are reclaimed from PCEC, then the amounts reclaimed;

 

   

all costs and expenses for recording the conveyances and, at the applicable times, terminations and/or releases thereof;

 

   

all administrative hedge costs (in respect of commodity derivative contracts existing prior to the date of the conveyances, as further described in the conveyances);

 

   

all hedge settlement costs (in respect of commodity derivative contracts existing prior to the date of the conveyances, as further described in the conveyances);

 

   

amounts previously included in gross profits but subsequently paid as a refund, interest or penalty;

 

   

amounts charged to PCEC equal to $1.00 per Boe of production, which fee will change on an annual basis commencing on April 1, 2013, based on changes to the CPI (the operating and services fee is expected to be $86,250 per month for the twelve months ending March 31, 2013); and

 

   

at the option of PCEC (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to the limitations described below (provided that such costs shall not be debited from gross profits when actually incurred).

As mentioned above, the costs deducted in the net profits determination will be reduced by certain offset amounts. The offset amounts are further described in the conveyances, and include, among other things, certain net proceeds attributable to the treatment or processing of hydrocarbons produced from the Underlying Properties, all of the payments received by PCEC from commodity derivative contract counterparties upon settlement of commodity derivative contracts and certain other non-production revenues, including salvage value for equipment related to plugged and abandoned wells. If the offset amounts exceed the costs during a monthly period, the ability to use such excess amounts to offset costs will be deferred and utilized as offsets in the next monthly period to the extent such amounts, plus accrued interest thereon, together with other offsets to costs, for the applicable month, are less than the costs arising in such month.

The trust is not liable to the owners of the Underlying Properties, PCEC, or any other operator for any operating, capital or other costs or liabilities attributable to the Underlying Properties. In the event that the net profits relating to the Developed Properties for any computation period is a negative amount, the trust will receive no payment for the Developed Properties for that period, and any such negative amount plus accrued interest at a prime rate (as described in the conveyance) will be deducted from gross profits for the Developed

 

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Properties in the following computation period for purposes of determining the net profits relating to the Developed Properties for that following computation period. In the event that the net profits relating to the Remaining Properties for any computation period is a negative amount, the trust will receive no payment for the Remaining Properties for that period, and any such negative amount plus accrued interest at a prime rate (as described in the conveyance) plus 5.0% will be deducted from gross profits for the Remaining Properties in the following computation period for purposes of determining the net profits relating to the Remaining Properties for that following computation period.

Gross profits and net profits are calculated on a cash basis, except that certain costs, primarily ad valorem taxes and expenditures of a material amount, may be determined on an accrual basis.

Additional Provisions

If a controversy arises as to the sales price of any production, then for purposes of determining gross profits:

 

   

any proceeds that are withheld for any reason (other than at the request of PCEC) are not considered received until such time that the proceeds are actually collected;

 

   

amounts received and promptly deposited with a nonaffiliated escrow agent will not be considered to have been received until disbursed to it by the escrow agent; and

 

   

amounts received and not deposited with an escrow agent will be considered to have been received.

The trustee is not obligated to return any cash received from the Net Profits Interests. Any overpayments made to the trust by PCEC due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the trust until PCEC recovers the overpayments plus interest at a prime rate (as described in the conveyances).

The conveyances generally permit PCEC to transfer without the consent or approval of the trust unitholders all or any part of its interest in the Underlying Properties, subject to the Net Profits Interests. The trust unitholders are not entitled to any proceeds of a sale or transfer of PCEC’s interest. Except in certain cases where the Net Profits Interests are released, following a sale or transfer, the Underlying Properties will continue to be subject to the Net Profits Interests, and the gross profits attributable to the transferred property will be calculated (as part of the computation of net profits described in this prospectus), paid and distributed by the transferee to the trust. PCEC will have no further obligations, requirements or responsibilities with respect to any such transferred interests.

In addition, PCEC may, without the consent of the trust unitholders, require the trust to release the Net Profits Interests associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior twelve months, provided that the Net Profits Interests covered by such releases cannot exceed, during any twelve month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by PCEC to a non-affiliate of the relevant Underlying Properties, are conditioned upon an amount equal to the fair market value (net of sales costs) to the trust of such Net Profits Interests and will be treated as an offset amount against costs and expenses. PCEC has not identified for sale any of the Underlying Properties.

As the designated operator of a property comprising the Underlying Properties, PCEC may enter into farm-out, operating, participation and other similar agreements to develop the property, but any transfers made in connection with such agreements will be made subject to the Net Profits Interests. PCEC may enter into any of these agreements without the consent or approval of the trustee or any trust unitholder.

PCEC will have the right to release, surrender or abandon its interest in any Underlying Property if PCEC determines in good faith and in accordance with the reasonably prudent operator standard that such Underlying Property that will no longer produce (or be capable of producing) hydrocarbons in paying quantities (determined

 

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without regard to the Net Profits Interests). Where PCEC does not operate the Underlying Properties, PCEC is required to use commercially reasonable efforts to exercise its contractual rights to cause the operators of such Underlying Properties to act as a reasonably prudent operator. Upon such release, surrender or abandonment, the portion of the Net Profits Interests relating to the affected property will also be released, surrendered or abandoned, as applicable. PCEC will also have the right to abandon an interest in the Underlying Properties if (a) such abandonment is necessary for health, safety or environmental reasons or (b) the hydrocarbons that would have been produced from the abandoned portion of the Underlying Properties would reasonably be expected to be produced from wells located on the remaining portion of the Underlying Properties.

PCEC must maintain books and records sufficient to determine the amounts payable for the Net Profits Interests to the trust. Monthly and annually, PCEC must deliver to the trustee a statement of the computation of the net profits for each computation period. The trustee has the right to inspect and review the books and records maintained by PCEC during normal business hours and upon reasonable notice.

 

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DESCRIPTION OF THE TRUST AGREEMENT

The following information and the information included under “Description of the Trust Units” summarize the material information contained in the trust agreement and the conveyances. For more detailed provisions concerning the trust and the conveyances, you should read the trust agreement, a copy of which has been filed as an exhibit to the registration statement, and the conveyances, forms of which will be filed as exhibits to the registration statement. Please read “Where You Can Find More Information.”

Creation and Organization of the Trust; Amendments

Immediately prior to the closing of this offering, PCEC will convey, or cause to be conveyed, to the trust the Net Profits Interests in consideration of the receipt of              trust units. The trust’s first monthly distribution will consist of an amount in cash paid by PCEC equal to the amount that would have been payable to the trust had the Net Profits Interests been in effect beginning on April 1, 2012, less any general and administrative expenses and reserves of the trust beginning on April 1, 2012. After the offering made hereby, PCEC will own its net interests in the Underlying Properties subject to and burdened by the Net Profits Interests.

The trust was created under Delaware law to acquire and hold the Net Profits Interests for the benefit of the trust unitholders pursuant to an agreement among PCEC, the trustee and the Delaware trustee. The Net Profits Interests are passive in nature and neither the trust nor the trustee has any control over or responsibility for costs relating to the operation of the properties comprising the Underlying Properties. PCEC does not have any contractual commitments to the trust to provide additional funding or to conduct further drilling on or to maintain their ownership interest in any of the Underlying Properties. After the conveyances of the Net Profits Interests, however, PCEC will retain an interest in the Underlying Properties. For a description of the Underlying Properties and other information relating to them, please read “The Underlying Properties.”

The trust agreement will provide that the trust’s business activities will be limited to owning the Net Profits Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyances related to the Net Profits Interests. As a result, the trust will not be permitted to acquire other oil and natural gas properties or net profits interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interests.

The beneficial interest in the trust is divided into              trust units. Each of the trust units represents an equal undivided beneficial interest in the assets of the trust. You will find additional information concerning the trust units in “Description of the Trust Units.”

Amendment of the trust agreement requires the affirmative vote of the holders of at least 75% of the outstanding trust units. However, no amendment may:

 

   

increase the power of the trustee or the Delaware trustee to engage in business or investment activities; or

 

   

alter the rights of the trust unitholders as among themselves.

In addition, certain sections of the trust agreement cannot be amended without the consent of PCEC. Certain amendments to the trust agreement do not require the vote of the trust unitholders. The trustee may, without approval of the trust unitholders, from time to time supplement or amend the trust agreement in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders, to comply with changes in applicable law or to change the name of the trust, provided such supplement or amendment does not materially adversely affect the interests of the trust unitholders. The affairs of the trust will be managed by the trustee. PCEC has no ability to manage or influence the operations of the trust and will not owe any fiduciary duties or liabilities to the trust or the unitholders. Likewise, the trust has no ability to manage or influence the operation of PCEC.

 

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Assets of the Trust

Upon completion of this offering, the assets of the trust will consist of the Net Profits Interests and any cash and temporary investments being held for the payment of expenses and liabilities and for distribution to the trust unitholders.

Duties and Powers of the Trustee

The duties of the trustee are specified in the trust agreement and by the laws of the state of Delaware, except as modified by the trust agreement. The trustee’s principal duties consist of:

 

   

collecting cash attributable to the Net Profits Interests;

 

   

paying expenses, charges and obligations of the trust from the trust’s assets;

 

   

distributing distributable cash to the trust unitholders;

 

   

causing to be prepared and distributed a tax information report for each trust unitholder and to prepare and file tax returns on behalf of the trust;

 

   

causing to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading;

 

   

causing to be prepared and filed a reserve report by or for the trust by independent reserve engineers as of December 31 of each year in accordance with criteria established by the SEC;

 

   

establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002;

 

   

enforcing the rights under certain agreements entered into in connection with this offering;

 

   

taking any action it deems necessary, desirable or advisable to best achieve the purposes of the trust; and

 

   

providing to PCEC any unitholder information necessary for PCEC to fulfill any applicable tax withholding requirements.

In connection with the formation of the trust, the trust will enter into several agreements with PCEC that impose obligations upon PCEC that are enforceable by the trustee on behalf of the trust, including the conveyances, an operating and services agreement and a registration rights agreement. For example, the trust will enter into an operating and services agreement with PCEC pursuant to which PCEC will perform specified operating and informational services on behalf of the trust in a good and workmanlike manner in accordance with the sound and prudent practices of providers of similar services. The trustee has the power and authority under the trust agreement to enforce these agreements on behalf of the trust. Additionally, the trustee may from time to time supplement or amend the conveyances, the operating and services agreement and the registration rights agreement to which the trust is a party without the approval of trust unitholders in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the trust unitholders, to comply with changes in applicable law or to change the name of the trust. Such supplement or amendment, however, may not materially adversely affect the interests of the trust unitholders.

The trustee may create a cash reserve to pay for future liabilities of the trust. If the trustee determines that the cash on hand and the cash to be received are, or will be, insufficient to cover the trust’s liabilities, the trustee may cause the trust to borrow funds to pay liabilities of the trust. The trust calculates net profits from the Underlying Properties separately for each of the Developed Properties and the Remaining Properties. Any excess costs for either the Developed Properties or the Remaining Properties will not reduce net profits calculated for the other. Accordingly, the cash on hand for either the Developed Properties or the Remaining Properties will not be applied to cover the costs of the other. The trustee may cause the trust to borrow the funds from any person, including itself or its affiliates, but neither the trustee nor any of its affiliates has any intention or obligation to do so. The trustee may also cause the trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the entity serving as trustee or Delaware trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated

 

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commercial customer with whom it did not have a fiduciary relationship, and such entity shall be entitled to enforce its rights with respect to any such indebtedness and security interest as if it were not then serving as trustee or Delaware trustee. If the trustee causes the trust to borrow funds, the trust unitholders will not receive distributions until the borrowed funds are repaid.

Each month, the trustee will pay trust obligations and expenses and distribute to the trust unitholders the remaining proceeds received from the Net Profits Interests. The cash held by the trustee as a reserve against future liabilities or for distribution at the next distribution date must be invested in:

 

   

interest bearing obligations of the United States government;

 

   

money market funds that invest only in United States government securities;

 

   

repurchase agreements secured by interest-bearing obligations of the United States government; or

 

   

bank certificates of deposit.

Alternatively, cash held for distribution at the next distribution date may be held in a noninterest bearing account.

The trust may not acquire any asset except the Net Profits Interests, cash and temporary cash investments, and it may not engage in any investment activity except investing cash on hand.

The trust may merge or consolidate with or convert into one or more limited partnerships, general partnerships, corporations, business trusts, limited liability companies, associations or unincorporated businesses if such transaction is agreed to by the trustee and by the affirmative vote of the holders of a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present and such transaction is permitted under the Delaware Statutory Trust Act and any other applicable law.

PCEC may cause the trustee to sell all or any part of the trust estate, including all or any portion of the Net Profits Interests, if approved by the holders of at least 75% of the outstanding trust units. In addition, PCEC may, without the consent of the trust unitholders, require the trust to release the Net Profits Interests associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior twelve months, provided that the Net Profits Interests covered by such releases cannot exceed, during any twelve month period, an aggregate fair market value to the trust of $500,000. These releases will be made only in connection with a sale by PCEC to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair value to the trust of such Net Profits Interests being treated as an offset amount against costs and expenses.

Upon dissolution of the trust, the trustee must sell the Net Profits Interests. No trust unitholder approval is required in this event.

The trustee may require any trust unitholder to dispose of his trust units if an administrative or judicial proceeding seeks to cancel or forfeit any of the property in which the trust holds an interest because of the nationality or any other status of that trust unitholder. If a trust unitholder fails to dispose of his trust units, the trustee has the right to purchase them on behalf of the trust and to borrow funds to make that purchase.

The trustee will maintain a website for filings made by the trust with the SEC.

The trustee may agree to modifications of the terms of the conveyances or to settle disputes involving the conveyances without the consent of any trust unitholder. The trustee may not agree to modifications or settle disputes involving the Net Profits Interests part of the conveyances if these actions would change the character of the Net Profits Interests in such a way that the Net Profits Interests becomes a working interest or that the trust would fail to continue to qualify as a grantor trust for U.S. federal income tax purposes.

 

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Fees and Expenses

Because the trust does not conduct an active business and the trustee has little power to incur obligations, it is expected that the trust will only incur liabilities for routine administrative expenses, such as the trustee’s fees, accounting, engineering, legal, tax advisory, the PCEC operating and services fee and other professional fees and other fees and expenses applicable to public companies. The trust will also be responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual, quarterly and monthly reports to trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees. The trust’s general and administrative expenses are estimated to be approximately $850,000 for the twelve months ending March 31, 2013. Included in the $850,000 annual estimate is an annual administrative fee of $200,000 and $2,000 for the trustee and Delaware trustee, respectively. The trust will pay, out of the first cash payment received by the trust, the trustee’s and Delaware trustee’s legal expenses incurred in forming the trust as well as their acceptance fees in the amount of $10,000 and $1,500, respectively. These costs will be deducted by the trust before distributions are made to trust unitholders.

In addition, the PCEC operating and services fee is an amount equal to $1.00 per Boe of production and is expected to be approximately $1,035,000 for the twelve months ending March 31, 2013. The PCEC operating and services fee will change on an annual basis commencing on April 1, 2013, based on changes to the CPI. Please read “The Trust.” The PCEC operating and services fee, along with the trust’s general and administrative expenses, for subsequent years could be greater or less depending on future events that cannot be predicted.

PCEC has agreed to provide the trust at the closing of this offering with a $1.0 million letter of credit to be used by the trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses as they become due. Further, if the trust requires more than the $1.0 million under the letter of credit to pay administrative expenses, PCEC has agreed to loan funds to the trust necessary to pay such expenses. Any funds provided under the letter of credit or loaned by PCEC may only be used for the payment of current accounts or other obligations to trade creditors in connection with obtaining goods or services or for the payment of other accrued current liabilities arising in the ordinary course of the trust’s business, and may not be used to satisfy trust indebtedness. If the trust draws on the letter of credit or PCEC loans funds to the trust, no further distributions will be made to trust unitholders (except in respect of any previously determined monthly cash distribution amount) until such amounts drawn or borrowed are repaid. Any loan made by PCEC will be on an unsecured basis, and the terms of such loan will be substantially the same as those which would be obtained in an arm’s-length transaction between PCEC and an unaffiliated third party.

Fiduciary Responsibility and Liability of the Trustee

The trustee will not make business or investment decisions affecting the assets of the trust except to the extent it enforces its rights under the conveyances related to the Net Profits Interests and the operating and services agreement described above under “—Duties and Powers of the Trustee” that will be executed in connection with this offering. Therefore, substantially all of the trustee’s functions under the trust agreement are expected to be ministerial in nature. Please read “—Duties and Powers of the Trustee” above. The trust agreement, however, provides that the trustee may:

 

   

charge for its services as trustee;

 

   

retain funds to pay for future expenses and deposit them with one or more banks or financial institutions (which may include the trustee to the extent permitted by law);

 

   

lend funds at commercial rates to the trust to pay the trust’s expenses; and

 

   

seek reimbursement from the trust for its out-of-pocket expenses.

 

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In discharging its duty to trust unitholders, the trustee may act in its discretion and will be liable to the trust unitholders only for its own fraud, gross negligence or willful misconduct. The trustee will not be liable for any act or omission of its agents or employees unless the trustee acted with fraud, gross negligence or willful misconduct in their selection, retention or supervision. The trustee will be indemnified individually or as the trustee for any liability or cost that it incurs in the administration of the trust, except in cases of fraud, gross negligence or willful misconduct. The trustee will have a lien on the assets of the trust as security for this indemnification and its compensation earned as trustee. Trust unitholders will not be liable to the trustee for any indemnification. Please read “Description of the Trust Units—Liability of Trust Unitholders.”

The trustee may consult with counsel, accountants, tax advisors, geologists, engineers and other parties the trustee believes to be qualified as experts on the matters for which advice is sought. The trustee will be protected in relying or reasonably acting upon the opinion of the expert.

Except as expressly set forth in the trust agreement, none of PCEC, the trustee, the Delaware trustee nor the other indemnified parties have any duties or liabilities, including fiduciary duties, to the trust or any trust unitholder. The provisions of the trust agreement, to the extent they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties of these persons otherwise existing at law or in equity, are agreed by the trust unitholders to replace such other duties and liabilities of these persons.

Duration of the Trust; Sale of the Net Profits Interests

The trust will dissolve upon the earliest to occur of the following:

 

   

the trust, upon the approval of the holders of at least 75% of the outstanding trust units, sells the Net Profits Interests;

 

   

the annual cash available for distribution to the trust is less than $2.0 million for each of any two consecutive years;

 

   

the holders of at least 75% of the outstanding trust units vote in favor of dissolution; or

 

   

the trust is judicially dissolved.

The trustee would then sell all of the trust’s assets, either by private sale or public auction, and, after payment or the making of reasonable provision for payment of all liabilities of the trust, distribute the net proceeds of the sale to the trust unitholders.

Dispute Resolution

Any dispute, controversy or claim that may arise between PCEC and the trustee relating to the trust will be submitted to binding arbitration before a tribunal of three arbitrators.

Compensation of the Trustee and the Delaware Trustee

The trustee’s and the Delaware trustee’s compensation will be paid out of the trust’s assets. Please read “—Fees and Expenses.”

Miscellaneous

The principal offices of the trustee are located at 919 Congress Avenue, Suite 500, Austin, Texas 78701, and its telephone number is 1-800-852-1422.

The Delaware trustee and the trustee may resign at any time or be removed with or without cause at any time by the affirmative vote of not less than a majority of the trust units present in person or by proxy at a meeting of such holders where a quorum is present. With certain exceptions, any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and undivided profits of at least $20,000,000, in the case of the Delaware trustee, and $100,000,000, in the case of the trustee.

 

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DESCRIPTION OF THE TRUST UNITS

Each trust unit is a unit of beneficial interest in the trust assets and is entitled to receive cash distributions from the trust on a pro rata basis. Each trust unitholder has the same rights regarding each of his trust units as every other trust unitholder has regarding his units. The trust units will be in book-entry form only and will not be represented by certificates. The trust will have trust units outstanding upon completion of this offering.

Distributions and Income Computations

Each month, the trustee will determine the amount of funds available for distribution to the trust unitholders. Available funds are the excess cash, if any, received by the trust from the Net Profits Interests and other sources (such as interest earned on any amounts reserved by the trustee) that month, over the trust’s liabilities for that month. Available funds will be reduced by any cash the trustee decides to hold as a reserve against future liabilities. The holders of trust units as of the applicable record date (generally the last business day of each calendar month) are entitled to monthly distributions payable on or before the 10th business day after the record date. The first distribution to trust unitholders purchasing trust units in this offering will be made on or about June 15, 2012 to trust unitholders owning trust units on or about May 31, 2012.

Unless otherwise advised by counsel or the IRS, the trustee will treat the income and expenses of the trust for each month as belonging to the trust unitholders of record on the monthly record date. Trust unitholders generally will recognize income and expenses for tax purposes in the month the trust receives or pays those amounts, rather than in the month the trust distributes the cash to which such income or expenses (as applicable) relate. Minor variances may occur. For example, the trustee could establish a reserve in one month that would not result in a tax deduction until a later month. Please read “United States Federal Income Tax Considerations.”

Transfer of Trust Units

Trust unitholders may transfer their trust units in accordance with the trust agreement. The trustee will not require either the transferor or transferee to pay a service charge for any transfer of a trust unit. The trustee may require payment of any tax or other governmental charge imposed for a transfer. The trustee may treat the owner of any trust unit as shown by its records as the owner of the trust unit. The trustee will not be considered to know about any claim or demand on a trust unit by any party except the record owner. A person who acquires a trust unit after any monthly record date will not be entitled to the distribution relating to that monthly record date. Delaware law will govern all matters affecting the title, ownership or transfer of trust units.

Periodic Reports

The trustee will file all required trust federal and state income tax and information returns. The trustee will prepare and mail to trust unitholders annual reports that trust unitholders need to correctly report their share of the income and deductions of the trust. The trustee will also cause to be prepared and filed reports required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the trust units are listed or admitted to trading, and will also cause the trust to comply with all of the provisions of the Sarbanes-Oxley Act, including but not limited to, establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.

Each trust unitholder and his representatives may examine, for any proper purpose, during reasonable business hours, the records of the trust and the trustee, subject to such restrictions as are set forth in the trust agreement.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act and the trust agreement, trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. No assurance can be given, however, that the courts in jurisdictions outside of Delaware will give effect to such limitation.

 

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Voting Rights of Trust Unitholders

The trustee or trust unitholders owning at least 10% of the outstanding trust units may call meetings of trust unitholders. The trust will be responsible for all costs associated with calling a meeting of trust unitholders unless such meeting is called by the trust unitholders, in which case the trust unitholders will be responsible for all costs associated with calling such meeting of trust unitholders. Meetings must be held in such location as is designated by the trustee in the notice of such meeting. The trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of trust units outstanding must be present or represented to have a quorum. Each trust unitholder is entitled to one vote for each trust unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.

Unless otherwise required by the trust agreement, a matter may be approved or disapproved by the affirmative vote of a majority of the trust units present in person or by proxy at a meeting where there is a quorum. This is true, even if a majority of the total trust units did not approve it. The affirmative vote of the holders of at least 75% of the outstanding trust units is required to:

 

   

dissolve the trust;

 

   

amend the trust agreement (except with respect to certain matters that do not adversely affect the rights of trust unitholders in any material respect); or

 

   

approve the sale of all or any material part of the assets of the trust (including the sale of the Net Profits Interests).

In addition, certain amendments to the trust agreement may be made by the trustee without approval of the trust unitholders. Please read “Description of the Trust Agreement—Creation and Organization of the Trust; Amendments.”

Comparison of Trust Units and Common Stock

Trust unitholders have more limited voting rights than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of trust unitholders or for annual or other periodic re-election of the trustee.

You should also be aware of the following ways in which an investment in trust units is different from an investment in common stock of a corporation.

 

    

Trust Units

  

Common Stock

Voting

   The trust agreement provides voting rights to trust unitholders to remove and replace the trustee and to approve or disapprove amendments to the trust agreement and certain major trust transactions.    Unless otherwise provided in the certificate of incorporation, the corporate statutes provide voting rights to stockholders to elect directors and to approve or disapprove amendments to the certificate of incorporation and certain major corporate transactions.

Income Tax

   The trust is not subject to income tax; trust unitholders are subject to income tax on their pro rata share of trust income, gain, loss and deduction.    Corporations are taxed on their income and their stockholders are taxed on dividends.

Distributions

   Substantially all of the cash receipts of the trust are required to be distributed to trust unitholders.    Unless otherwise provided in the certificate of incorporation, stockholders are entitled to receive dividends solely at the discretion of the board of directors.

 

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Trust Units

  

Common Stock

Business and Assets

   The business of the trust is limited to specific assets with a finite economic life.    Unless otherwise provided in the certificate of incorporation, a corporation conducts an active business for an unlimited term and can reinvest its earnings and raise additional capital to expand.

Fiduciary Duties

   The trustee shall not be liable to the trust unitholders for any of its acts or omissions absent its own fraud, gross negligence or willful misconduct.    Officers and directors have a fiduciary duty of loyalty to the corporation and its stockholders and a duty to exercise due care in the management and administration of a corporation’s affairs.

 

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TRUST UNITS ELIGIBLE FOR FUTURE SALE

General

Prior to this offering, there has been no public market for the trust units. Sales of substantial amounts of the trust units in the open market, or the perception that those sales could occur, could adversely affect prevailing market prices.

Upon completion of this offering, there will be outstanding              trust units. All of the trust units sold in this offering, or              trust units if the underwriters exercise their option to purchase additional trust units in full, will be freely tradable without restriction under the Securities Act of 1933, as amended, or the “Securities Act”. All of the trust units outstanding other than the trust units sold in this offering (a total of              trust units, or              trust units if the underwriters exercise their option to purchase additional trust units in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and may not be sold other than through registration under the Securities Act or pursuant to an exemption from registration, subject to the restrictions on transfer contained in the lock-up agreements described below and in “Underwriting.”

Lock-Up Agreements

In connection with this offering, PCEC has agreed, for a period of 180 days after the date of this prospectus, not to offer, sell, contract to sell or otherwise dispose of or transfer any trust units or any securities convertible into or exchangeable for trust units unless Barclays Capital Inc. consents to a shorter period, subject to specified exceptions. Please read “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements,              trust units, or              trust units if the underwriters exercise their option to purchase additional trust units in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144, or through registration under the Securities Act.

Rule 144

The trust units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any trust units owned by an “affiliate” of the trust, including those held by PCEC, 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 to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

   

1.0% of the total number of the securities outstanding, or

 

   

the average weekly reported trading volume of the trust units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manners of sale provisions, holding period requirements, notice requirements and the availability of current public information about the trust. A person who is not deemed to have been an affiliate of PCEC or the trust at any time during the three months preceding a sale, and who has beneficially owned his trust units for at least nine months (provided the trust is in compliance with the current public information requirement) or one year (regardless of whether the trust is in compliance with the current public information requirement), would be entitled to sell trust units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

 

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Registration Rights

The trust intends to enter into a registration rights agreement with PCEC in connection with PCEC’s contribution to the trust of the Net Profits Interests. In the registration rights agreement, the trust will agree, for the benefit of PCEC and any transferee of PCEC’s trust units, or the “holders,” to register the trust units they hold. Specifically, the trust will agree:

 

   

subject to the restrictions described above under “—Lock-Up Agreements” and under “Underwriting—Lock-Up Agreements,” to use its reasonable best efforts to file a registration statement, including, if so requested, a shelf registration statement, with the SEC as promptly as practicable following receipt of a notice requesting the filing of a registration statement from holders representing a majority of the then outstanding registrable trust units;

 

   

to use its commercially reasonable efforts to cause the registration statement or shelf registration statement to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and

 

   

to use its commercially reasonable efforts to maintain the effectiveness of the registration statement under the Securities Act for 90 days (or for three years if a shelf registration statement is requested) after the effectiveness thereof or until the trust units covered by the registration statement have been sold pursuant to such registration statement, PCEC ceases to be an affiliate of the trust for 10 years or until all registrable trust units:

 

   

have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities”;

 

   

have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are not assigned to the transferee of the trust units;

 

   

are held by the trust; or

 

   

have been sold in a private transaction in which the transferor’s rights under the registration rights agreement are assigned to a transferee that is not an affiliate of the trust and two years have passed since such transfer.

The holders will have the right to require the trust to file no more than five registration statements in aggregate.

In connection with the preparation and filing of any registration statement, PCEC will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the trust, which will be borne by the trust. Any underwriting discounts and commissions will be borne by the seller of the trust units.

 

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UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

This section is a summary of the material U.S. federal income tax considerations that may be relevant to prospective trust unitholders and, unless otherwise noted in the following discussion, is the opinion of Latham & Watkins LLP, counsel to the trust, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended, or the “Code,” existing and proposed Treasury regulations promulgated under the Code, or the “Treasury Regulations,” and current administrative rulings and court decisions, all of which are subject to change or different interpretation at any time, possibly with retroactive effect. Later changes in these authorities may cause the U.S. federal income tax consequences to vary substantially from the consequences described below.

The following discussion does not comment on all federal income tax matters affecting the trust or trust unitholders. The following discussion is limited to trust unitholders who hold the trust units as “capital assets” (generally, property held for investment). All references to “trust unitholders” (including U.S. trust unitholders and non-U.S. trust unitholders) are to beneficial owners of the trust units. This summary does not address the effect of the U.S. federal estate or gift tax laws or the tax considerations arising under the law of any state (except as provided in the limited summary below under “State Tax Considerations”), local or non-U.S. jurisdiction. Moreover, the discussion has only limited application to trust unitholders subject to special tax treatment such as, without limitation:

 

   

banks, insurance companies or other financial institutions;

 

   

trust unitholders subject to the alternative minimum tax;

 

   

tax-exempt organizations;

 

   

dealers in securities or commodities;

 

   

regulated investment companies;

 

   

real estate investment trusts;

 

   

traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;

 

   

non-U.S. trust unitholders (as defined below) that are “controlled foreign corporations” or “passive foreign investment companies”;

 

   

persons that are S-corporations, partnerships or other pass-through entities;

 

   

persons that own their interest in the trust units through S-corporations, partnerships or other pass-through entities;

 

   

persons that at any time own more than 5% of the aggregate fair market value of the trust units;

 

   

expatriates and certain former citizens or long-term residents of the United States;

 

   

U.S. trust unitholders (as defined below) whose functional currency is not the U.S. dollar;

 

   

persons who hold the trust units as a position in a hedging transaction, “straddle,” “conversion transaction” or other risk reduction transaction; or

 

   

persons deemed to sell the trust units under the constructive sale provisions of the Code.

Prospective investors are urged to consult their tax advisors as to the particular tax consequences to them of the ownership and disposition of an investment in trust units, including the applicability of any U.S. federal income, federal estate or gift tax, state, local and foreign tax laws, changes in applicable tax laws and any pending or proposed legislation.

 

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As used herein, the term “U.S. trust unitholder” means a beneficial owner of trust units that for U.S. federal income tax purposes is:

 

   

an individual who is a citizen of the United States or who is a resident of the United States for U.S. federal income tax purposes,

 

   

a corporation, or an entity treated as a corporation for U.S. federal income tax purposes, created or organized in or under the laws of the United States, a state thereof or the District of Columbia,

 

   

an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

 

   

a trust if it is subject to the primary supervision of a U.S. court and the control of one or more United States persons (as defined for U.S. federal income tax purposes) or that has a valid election in effect under applicable U.S. Treasury Regulations to be treated as a United States person.

The term “non-U.S. trust unitholder” means any beneficial owner of a trust unit that is an individual, corporation, estate or trust and that is not a U.S. trust unitholder.

If a partnership (including for this purpose any entity or arrangement treated as a partnership for U.S. federal income tax purposes) is a beneficial owner of trust units, the tax treatment of a partner in the partnership will depend upon the status of the partner and the activities of the partnership. A trust unitholder that is a partnership, and the partners in such partnership, should consult their own tax advisors about the U.S. federal income tax consequences of purchasing, owning and disposing of trust units.

Classification and Taxation of the Trust

In the opinion of Latham & Watkins LLP, for U.S. federal income tax purposes, the trust will be treated as a grantor trust and not as an unincorporated business entity. As a grantor trust, the trust will not be subject to tax at the trust level. Rather, the grantors, who in this case are the trust unitholders, will be considered, for U.S. federal income tax purposes, to own and receive the trust’s assets and income and will be directly taxable thereon as though no trust were in existence.

No ruling has been or will be requested from the IRS with respect to the U.S. federal income tax treatment of the trust, including a ruling as to the status of the trust as a grantor trust or as a partnership for U.S. federal income tax purposes. Thus, no assurance can be provided that the opinions and statements set forth in this discussion of U.S. federal income tax considerations would be sustained by a court if contested by the IRS.

The remainder of the discussion below is based on Latham & Watkins LLP’s opinion that the trust will be classified as a grantor trust for U.S. federal income tax purposes.

Reporting Requirements for Widely-Held Fixed Investment Trusts

Under Treasury Regulations, the trust is classified as a widely-held fixed investment trust. Those Treasury Regulations require the sharing of tax information among trustees and intermediaries that hold a trust interest on behalf of or for the account of a beneficial owner or any representative or agent of a trust interest holder of fixed investment trusts that are classified as widely-held fixed investment trusts. These reporting requirements provide for the dissemination of trust tax information by the trustee to intermediaries who are ultimately responsible for reporting the investor-specific information through Form 1099 to the investors and the IRS. Every trustee or intermediary that is required to file a Form 1099 for a trust unitholder must furnish a written tax information statement that is in support of the amounts as reported on the applicable Form 1099 to the trust unitholder. Any generic tax information provided by the trustee of the trust is intended to be used only to assist trust unitholders in the preparation of their federal and state income tax returns.

 

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Direct Taxation of Trust Unitholders

Because the trust will be treated as a grantor trust for U.S. federal income tax purposes, trust unitholders will be treated for such purposes as owning a direct interest in the assets of the trust, and each trust unitholder will be taxed directly on his pro rata share of the income and gain attributable to the assets of the trust and will be entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the trust (subject to certain limitations discussed below). Information returns will be filed as required by the widely held fixed investment trust rules, reporting to the trust unitholders all items of income, gain, loss, deduction and credit, which will be allocated based on record ownership on the monthly record dates and must be included in the tax returns of the trust unitholders. Income, gain, loss, deduction and credits attributable to the assets of the trust will be taken into account by trust unitholders consistent with their method of accounting and without regard to the taxable year or accounting method employed by the trust.

Following the end of each month, the trustee will determine the amount of funds available as of the end of such month for distribution to the trust unitholders and will make distributions of available funds, if any, to the trust unitholders on or before the 10th business day after the record date, which will generally be on or about the last business day of each calendar month. In certain circumstances, however, a trust unitholder will not receive a distribution of cash attributable to the income from a month. For example, if the trustee establishes a reserve or borrows money to satisfy liabilities of the trust, income associated with the cash used to establish that reserve or to repay that loan must be reported by the trust unitholder, even though that cash is not distributed to him.

As described above, the trust will allocate items of income, gain, loss, deductions and credits to trust unitholders based on record ownership on the monthly record dates. It is possible that the IRS could disagree with this allocation method and could assert that income and deductions of the trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by the issue and result in an increase in the administrative expense of the trust in subsequent periods.

The trust estimates that a purchaser of trust units in this offering who owns such trust units through the record date for distributions for the month ending December 31, 2014, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be approximately     % of the cash distributed with respect to that period. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond the trust’s control. Further, the estimates are based on current tax law and tax reporting positions that the trust will adopt and with which the IRS could disagree. Accordingly, the trust cannot assure unitholders that these estimates will prove to be correct. The actual percentage of distributions that will correspond to taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the trust units.

Tax Classification of the Net Profits Interests

For U.S. federal income tax purposes, the Net Profits Interests attributable to the Developed Properties, or the “Developed NPI,” or the Remaining Properties, or the “Remaining NPI,” will have the tax characteristics of mineral royalty interests to the extent, at the time of its creation, such Developed NPI or Remaining NPI is reasonably expected to have an economic life that corresponds substantially to the economic life of the mineral property or properties burdened thereby. Payments out of production that are received in respect of a mineral interest that constitutes a royalty interest for U.S. federal income tax purposes are taxable under current law as ordinary income subject to an allowance for cost or percentage depletion in respect of such income.

Based on the reserve report and representations made by PCEC regarding the expected economic life of the Underlying Properties and the expected duration of the Net Profits Interests, the Developed NPI will and the Remaining NPI should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of production from the mineral interests they burden.

 

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Consistent with the foregoing, PCEC and the trust intend to treat the Net Profits Interests as mineral royalty interests for U.S. federal income tax purposes. The remainder of this discussion assumes that the Net Profits Interests are treated as mineral royalty interests. No assurance can be given that the IRS will not assert that such interest should be treated differently. Any such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in trust units. Please read “—Tax Consequences to U.S. Trust Unitholders.”

PCEC and the trust intended to treat the portion of the purchase price of the trust units attributable to the right to receive a distribution based on the profits from and after April 1, 2012 attributable to production from the Underlying Properties for the period commencing April 1, 2012, and ending on the closing date of this offering as a tax-free return of capital when such distribution is received. The tax treatment of such a distribution portion is subject to uncertainty because there are no authorities that directly address the treatment of such a payment and, as a result, Latham & Watkins LLP is unable to opine on the tax treatment of such amounts.

Tax Consequences to U.S. Trust Unitholders

Royalty Income and Depletion

Consistent with the discussion above in “—Tax Classification of the Net Profits Interests,” the payments out of production that are received by the trust in respect of the Net Profits Interests constitute ordinary income received in respect of a mineral royalty interest. Trust unitholders should be entitled to deductions for the greater of either cost depletion or (if allowable) percentage depletion with respect to such income. Although the Code requires each trust unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying royalty interests for depletion and other purposes, the trust intends to furnish each of the trust unitholders with information relating to this computation for U.S. federal income tax purposes. Each trust 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 trust unitholders who qualify under the independent producer exemption contained in section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas or derivative products or the operation of a major refinery. In general, percentage depletion is calculated as an amount equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the trust 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 trust unitholder from the property for each taxable year, computed without the depletion allowance or certain loss carrybacks. A trust unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the trust unitholder’s average daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between oil and natural gas production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude 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 trust unitholder’s total taxable income from all sources for the year, computed without the depletion allowance and certain 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 trust unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is unlimited.

Unlike cost depletion, percentage depletion is not limited to the adjusted tax basis of the property, although, like cost depletion, it reduces the adjusted tax basis, but not below zero.

 

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In addition to the limitations on percentage depletion discussed above, the Budget Proposal and certain proposed legislation that includes proposals included in the Budget Proposal propose revisions to certain tax preferences applicable to taxpayers engaged in the exploration and production of natural resources, including the repeal of the deduction for percentage depletion with respect to oil and natural gas wells, in which case only cost depletion would be available. It is uncertain whether this or any other legislative proposals will ever be enacted and, if so, when it would become effective.

Trust 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 trust unitholder’s allocable 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 trust unitholder’s share of the total adjusted tax basis in the property.

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 trust unitholders. Further, because depletion is required to be computed separately by each trust unitholder and not by the trust, 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 trust unitholders for any taxable year. The trust encourages each prospective trust unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Tax Rates

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2013, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals and certain estates and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income would generally include certain income derived from investments such as the trust units and gain realized by a trust unitholder from a sale of trust units. In the case of an individual, the tax will be imposed on the lesser of (i) the trust unitholder’s net income from all investments and (ii) the amount by which the trust unitholder’s modified adjusted gross income exceeds $250,000 (if the trust unitholder is married and filing jointly or a surviving spouse), $125,000 (if the trust unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (1) undistributed net investment income, or (2) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Non-Passive Activity Income and Loss

Under current law, the income and losses of the trust will not be taken into account in computing the passive activity losses and income under Code section 469 for a trust unitholder who acquires and holds trust units as an investment.

Disposition of Trust Units

For U.S. federal income tax purposes, a sale of trust units will be treated as a sale by the U.S. trust unitholder of his interest in the assets of the trust. Generally, a U.S. trust unitholder will recognize gain or loss on

 

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a sale or exchange of trust units equal to the difference between the amount realized and the U.S. trust unitholder’s adjusted tax basis for the trust units sold. A U.S. trust unitholder’s adjusted tax basis in his trust units will be equal to the U.S. trust unitholder’s original purchase price for the trust units, reduced by deductions for depletion claimed by the trust unitholder, but not below zero. Except to the extent of the depletion recapture amount explained below, gain or loss on the sale of trust units by a trust unitholder who is an individual will generally be capital gain, and will be long-term capital gain, which is generally subject to tax at preferential rates, if the trust units have been held for more than twelve months. The deductibility of capital losses is limited. Upon the sale or other taxable disposition of his trust units, a trust unitholder will be treated as having sold his share of the Net Profits Interests and must treat as ordinary income his depletion recapture amount, which is an amount equal to the lesser of the gain on such sale or other taxable disposition or the sum of the prior depletion deductions taken with respect to the trust units, but not in excess of the initial tax basis of the trust units. The IRS could take the position that an additional portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of the sale that was allocable to the trust units sold even though the income is not distributed to the selling trust unitholder.

Trust Administrative Expenses

Expenses of the trust will include administrative expenses of the trustee. Certain miscellaneous itemized deductions may be subject to general limitations on deductibility. Under these rules, administrative expenses attributable to the trust units are miscellaneous itemized deductions that generally will have to be aggregated with an individual unitholder’s other miscellaneous itemized deductions to determine the excess over 2% of adjusted gross income. In addition, absent new applicable legislation, beginning on January 1, 2013, the amount of otherwise allowable itemized deductions for an individual unitholder whose adjusted gross income exceeds a specified amount for a taxable year will be reduced by the lesser of (i) 3% of the unitholder’s adjusted gross income over a specified amount, and (ii) 80% of the amount of itemized deductions that are otherwise allowable for such year. It is anticipated that the amount of such administrative expenses will not be significant in relation to the trust’s income.

Backup Withholding

Distributions of trust income generally will not be subject to backup withholding unless the trust unitholder is an individual or other noncorporate entity and fails to comply with specified reporting procedures.

Tax Treatment Upon Sale of the Net Profits Interests

The sale of the Net Profits Interests by the trust at or shortly after the date of dissolution of the trust will generally give rise to capital gain or loss to the trust unitholders for U.S. federal income tax purposes, except that any gain will be taxed at ordinary income rates to the extent of depletion deductions that reduced the trust unitholder’s adjusted basis in the Net Profits Interests. Such gain or loss will generally be long-term capital gain or loss, which is generally subject to tax at preferential rates, if the trust has been in existence and the trust unitholder has held his trust units for more than twelve months. The IRS could take the position that an additional portion of the sales proceeds is ordinary income to the extent of any accrued income at the time of the sale that was allocable to the trust units even though the income is not distributed to the trust unitholders.

Tax Consequences to Non-U.S. Trust Unitholders

The following is a summary of certain material U.S. federal income tax consequences that will apply to you if you are a non-U.S. trust unitholder. Non-U.S. trust unitholders should consult their tax advisors to determine the U.S. federal, state, local and foreign tax consequences that may be relevant to them.

Payments with Respect to the Trust Units

A non-U.S. trust unitholder will be subject to federal withholding tax on his share of gross royalty income from the Net Profits Interests. The withholding tax will apply at a 30% rate, or lower applicable treaty rate, to the

 

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gross royalty income received by the non-U.S. trust unitholder without the benefit of any deductions. However, if such gross royalty income is income effectively connected with a U.S. trade or business conducted by a non-U.S. trust unitholder and the non-U.S. trust unitholder provides an appropriate statement to that effect on IRS Form W-8ECI (or suitable substitute or successor form), then, unless an applicable tax treaty provides otherwise, such non-U.S. trust unitholder generally will be subject to U.S. federal income tax with respect to all such gross royalty income in the same manner as a U.S. trust unitholder, as described above. If such non-U.S. trust unitholder is a corporation, a branch profits tax (currently at the rate of 30%) may apply unless an applicable tax treaty provides otherwise.

Sale or Exchange of Trust Units

The Net Profits Interests will be treated as “United States real property interests” for U.S. federal income tax purposes. However, as long as the trust units are traded on an established securities exchange, gain realized on the sale or other taxable disposition of a trust unit by a non-U.S. trust unitholder will be subject to federal income tax only if:

 

   

the gain is otherwise effectively connected with business conducted by the non-U.S. trust unitholder in the United States (and, in the case of an applicable tax treaty, is attributable to a permanent establishment or fixed base maintained in the United States by the non-U.S. trust unitholder);

 

   

the non-U.S. trust unitholder is an individual who is present in the United States for at least 183 days in the year of the sale or other taxable disposition and certain other conditions are met; or

 

   

the non-U.S. trust unitholder owns currently, or owned at certain earlier times, directly, or by applying certain attribution rules, more than 5% of the trust units.

Gain realized by a non-U.S. trust unitholder upon the sale or other taxable disposition by the trust of all or any part of the Net Profits Interests would be subject to federal income tax, and distributions to the non-U.S. trust unitholder will be subject to withholding of U.S. tax (currently at the rate of 35%) to the extent distributions are attributable to such gains.

Tax Consequences to Tax Exempt Organizations

Employee benefit plans and most other organizations exempt from U.S. federal income tax including IRAs and other retirement plans are subject to U.S. federal income tax on unrelated business taxable income. Because the trust’s income is not expected to be unrelated business taxable income, such a tax-exempt organization is not expected to be taxed on income generated by ownership of trust units so long as neither the property held by the trust nor the trust units are treated as debt-financed property within the meaning of Section 514(b) of the Code. In general, trust property would be debt-financed if the trust incurs debt to acquire the property or otherwise incurs or maintains a debt that would not have been incurred or maintained if the property had not been acquired and a trust unit would be debt-financed if the trust unitholder incurs debt to acquire the trust unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the trust unit had not been acquired.

PROSPECTIVE INVESTORS IN TRUST UNITS ARE STRONGLY ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE TAX CONSEQUENCES TO THEM OF THE PURCHASE, OWNERSHIP AND DISPOSITION OF THE TRUST UNITS IN LIGHT OF THEIR OWN PARTICULAR CIRCUMSTANCES, INCLUDING THE TAX CONSEQUENCES UNDER STATE, LOCAL, FOREIGN AND OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN UNITED STATES FEDERAL OR OTHER TAX LAWS.

 

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STATE TAX CONSIDERATIONS

The following is a brief summary of certain information regarding state income taxes and other state tax matters affecting individuals who are trust unitholders. No opinion of counsel has been requested or received with respect to the state tax consequences of an investment in trust units. The trust is not providing any tax advice with respect to the state tax consequences applicable to any particular purchaser of trust units. Accordingly, prospective investors are urged to consult their tax advisors with respect to these matters.

The trust will own net profits interests burdening specified oil and natural gas properties located in the state of California. California currently imposes a personal income tax on individuals.

California imposes income taxes upon residents and nonresidents. In the case of nonresidents, income derived from tangible property within the state is subject to tax. The income tax laws of California are based on federal income tax laws. Assuming the trust is taxable as a grantor trust for federal income tax purposes, the trust unitholders will be subject to California income tax on their share of income from California net profits interests. A trust unitholder may be required to file state income tax returns and/or pay taxes in California and may be subject to penalties for failure to comply with such requirements. PCEC will be required to withhold an amount equal to 7% of the amounts paid to the trust that are attributable to each Net Profits Interest which, in turn, will reduce distributions to trust unitholders. Amounts withheld by PCEC would be treated as deductions against state income taxes otherwise payable.

 

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ERISA CONSIDERATIONS

The Employee Retirement Income Security Act of 1974, as amended, or “ERISA,” regulates pension, profit-sharing and other employee benefit plans to which it applies. ERISA also contains standards for persons who are fiduciaries of those plans. In addition, the Code provides similar requirements and standards which are applicable to qualified plans, which include these types of plans, and to individual retirement accounts, whether or not subject to ERISA.

A fiduciary of an employee benefit plan should carefully consider fiduciary standards under ERISA regarding the plan’s particular circumstances before authorizing an investment in trust units. A fiduciary should consider:

 

   

whether the investment satisfies the prudence requirements of Section 404(a)(1)(B) of ERISA;

 

   

whether the investment satisfies the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

   

whether the investment is in accordance with the documents and instruments governing the plan as required by Section 404(a)(1)(D) of ERISA.

A fiduciary should also consider whether an investment in trust units might result in direct or indirect nonexempt prohibited transactions under Section 406 of ERISA and Section 4975 of the Code. In deciding whether an investment involves a prohibited transaction, a fiduciary must determine whether there are plan assets in the transaction. The Department of Labor has published final regulations concerning whether or not an employee benefit plan’s assets would be deemed to include an interest in the underlying assets of an entity for purposes of the reporting, disclosure and fiduciary responsibility provisions of ERISA and analogous provisions of the Code. These regulations provide that the underlying assets of an entity will not be considered “plan assets” if the equity interests in the entity are a publicly offered security. PCEC expects that at the time of the sale of the trust units in this offering, they will be publicly offered securities. Fiduciaries, however, will need to determine whether the acquisition of trust units is a nonexempt prohibited transaction under the general requirements of ERISA Section 406 and Section 4975 of the Code.

The prohibited transaction rules are complex, and persons involved in prohibited transactions are subject to penalties. For that reason, potential employee benefit plan investors should consult with their counsel to determine the consequences under ERISA and the Code of their acquisition and ownership of trust units.

 

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SELLING TRUST UNITHOLDER

Immediately prior to the closing of the offering made hereby, PCEC will convey, or cause to be conveyed, to the trust the Net Profits Interests in exchange for              trust units. Of those trust units,              are being offered hereby and              are subject to the underwriters’ 30-day option to purchase additional trust units. PCEC has agreed not to sell any of such trust units for a period of 180 days after the date of this prospectus unless Barclays Capital Inc., acting as representative of the several underwriters, consents to a shorter period. Please read “Underwriting—Lock-Up Agreements.” PCEC is deemed to be an underwriter with respect to the trust units offered hereby.

The following table provides information regarding the selling trust unitholder’s ownership of the trust units.

 

      Ownership of Trust
Units Before Offering
    Number of
Trust  Units
Being Offered
    Ownership of Trust Units After
Offering
 

Selling Trust Unitholder

   Number    Percentage       Number    Percentage  

PCEC

        100.0          (1)             

 

(1) Includes              trust units subject to the underwriters’ 30-day option to purchase additional units.

Prior to this offering, there has been no public market for the trust units. Therefore, if PCEC disposes of all or a portion of the trust units it retains at the closing of this offering, the effect of such disposal on future market prices, if any, of market sales of such remaining trust units or the availability of trust units for sale cannot be predicted. Nevertheless, sales of substantial amounts of trust units in the public market could adversely affect future market prices.

 

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UNDERWRITING

Barclays Capital Inc. is acting as the representative of the underwriters of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from PCEC the respective number of trust units shown opposite its name below:

 

Underwriters

   Number of
Trust Units

Barclays Capital Inc.

  
  

 

  
  
  
  
  
  

 

Total

  
  

 

The underwriting agreement provides that the underwriters’ obligation to purchase trust units depends on the satisfaction of the conditions contained in the underwriting agreement including:

 

   

the obligation to purchase all of the trust units offered hereby (other than those trust units covered by their option to purchase additional trust units as described below), if any of the trust units are purchased;

 

   

the representations and warranties made by the trust and PCEC to the underwriters are true;

 

   

there is no material change in the business of the trust or PCEC or the financial markets; and

 

   

the trust and PCEC deliver customary closing documents to the underwriters.

PCEC is deemed to be an underwriter with respect to the trust units offered hereby.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions PCEC will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional trust units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to PCEC for the trust units.

 

      No Exercise    Full Exercise

Per trust unit

     

Total

     

Barclays Capital Inc. has advised PCEC that the underwriters propose to offer the trust 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 trust unit. After the offering, the representative may change the offering price and other selling terms.

The offering of the trust units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The expenses of the offering that are payable by PCEC are estimated to be $3,000,000 (excluding underwriting discounts and commissions).

 

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Option to Purchase Additional Trust Units

PCEC has granted the underwriters an option exercisable for 30 days after the date of this prospectus, to purchase, from time to time, in whole or in part, up to an aggregate of              trust units at the public offering price less underwriting discounts and commissions. This option may be exercised if the underwriters sell more than             trust 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 trust units based on the underwriter’s underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting Section.

Lock-Up Agreements

PCEC has agreed that, unless Barclays Capital Inc. consents to a shorter period, 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 trust units (including, without limitation, trust units that may be deemed to be beneficially owned by them in accordance with the rules and regulations of the SEC and trust units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for trust units or sell or grant options, rights or warrants with respect to any trust units or securities convertible into or exchangeable for trust units (other than the sale of the trust units to the underwriters in this offering and other than a pledge of PCEC’s trust units under PCEC’s senior secured credit facility, provided that PCEC will agree not to acquire any oil or natural gas properties for consideration exceeding $25 million, either individually or in the aggregate, for a period of 90 days after the date of this prospectus), (2) enter into any swap or other derivative transaction that transfers to another, in whole or in part, any of the economic consequences of ownership of the trust units, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any trust units or securities convertible, exercisable or exchangeable into trust units or any other securities of the trust or (4) publicly disclose the intention to do any of the foregoing for a period of 180 days after the date of this prospectus.

The 180-day restricted period described in the preceding paragraph will be extended if:

 

   

during the last 17 days of the 180-day restricted period the trust issues an earnings release or material news or a material event relating to the trust occurs; or

 

   

prior to the expiration of the 180-day restricted period, the trust announces that it 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 occurrence of a material event, unless such extension is waived in writing by Barclays Capital Inc.

Barclays Capital Inc., in its sole discretion, may release the trust 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 trust units and other securities from lock-up agreements, Barclays Capital Inc. will consider, among other factors, the holder’s reasons for requesting the release, the number of trust units and other securities for which the release is being requested and market conditions at the time. Barclays Capital Inc. has informed PCEC that it does not presently intend to release any trust units or other securities subject to the lock-up agreements.

 

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Offering Price Determination

Prior to this offering, there has been no public market for the trust units. The initial public offering price will be negotiated between the representative and PCEC. In determining the initial public offering price of the trust units, the representative will consider:

 

   

estimates of distributions to trust unitholders;

 

   

overall quality of the oil and natural gas properties attributable to the Underlying Properties;

 

   

the history and prospects for the energy industry;

 

   

PCEC’s financial information;

 

   

the prevailing securities markets at the time of this offering; and

 

   

the recent market prices of, and the demand for, publicly traded units of royalty trusts.

Indemnification

The trust and PCEC have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Selling Restrictions

Public Offer Selling Restrictions Under the Prospectus Directive

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of trust units described in this prospectus may not be made to the public in that relevant member state other than:

 

   

to any legal entity that is a qualified investor as defined in the Prospectus Directive;

 

   

to fewer than 100, or if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representative for any such offer; or

 

   

in any other circumstances that do not require the publication of a prospectus pursuant to Article 3(2) of the Prospectus Directive,

provided that no such offer of trust units shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of trust units to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the trust units to be offered so as to enable an investor to decide to purchase or subscribe the trust units, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of trust units through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the trust units as contemplated in this prospectus. Accordingly, no purchaser of the trust units, other than the underwriters, is authorized to make any further offer of the trust units on behalf of us or the underwriters.

 

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Notice to Prospective Investors in the United Kingdom

The trust may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (“FSMA”) that is not a “recognised collective investment scheme” for the purposes of FSMA (“CIS”) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

i) if the trust is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order; or

ii) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).

The trust units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such trust units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any trust units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to the trust or PCEC.

Stabilization, Short Positions and Penalty Bids

The representative 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 trust units, in accordance with Regulation M under the Exchange Act:

 

   

Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

 

   

A short position involves a sale by the underwriters of trust units in excess of the number of trust 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 trust units involved in the sales made by the underwriters in excess of the number of trust units they are obligated to purchase is not greater than the number of trust units that they may purchase by exercising their option to purchase additional trust units. In a naked short position, the number of trust units involved is greater than the number of trust units in their option to purchase additional trust units. The underwriters may close out any short position by either exercising their option to purchase additional trust units and/or purchasing trust units in the open market. In determining the source of trust units to close out the short position, the underwriters will consider, among other things, the price of trust units available for purchase in the open market as compared to the price at which they may purchase trust units through their option to purchase additional trust 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 trust units in the open market after pricing that could adversely affect investors who purchase in the offering.

 

   

Syndicate covering transactions involve purchases of the trust units in the open market after the distribution has been completed in order to cover syndicate short positions.

 

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Penalty bids permit the representative to reclaim a selling concession from a syndicate member when the trust 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 the trust units or preventing or retarding a decline in the market price of the trust units. As a result, the price of the trust 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.

None of the trust, PCEC or 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 trust units. In addition, none of the trust, PCEC or any of the underwriters make any representation that the representative 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 PCEC to allocate a specific number of trust units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representative 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 the trust, PCEC or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

New York Stock Exchange

The trust intends to apply to list the trust units on the New York Stock Exchange under the symbol “ROYT.” In connection with that listing, the underwriters have undertaken to sell the minimum number of trust units to the minimum number of beneficial owners necessary to meet the New York Stock Exchange listing requirements.

Discretionary Sales

The underwriters have informed PCEC that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of trust units offered by them.

FINRA Rules

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory and investment banking services for PCEC and the trust, for which they received or will receive customary fees and expenses.

 

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Because the Financial Industry Regulatory Authority, or “FINRA,” views the trust units offered hereby as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Conduct Rules. In no event will the maximum amount of compensation to be paid to FINRA members in connection with this offering exceed 10% of the offering proceeds. Investor suitability with respect to the trust units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

In the ordinary course of their various business activities, the underwriters and their respective affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of PCEC and the trust. The underwriters and their respective affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

 

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LEGAL MATTERS

Richards, Layton & Finger, P.A., as special Delaware counsel to the trust, will give a legal opinion as to the validity of the trust units. Latham & Watkins LLP, Houston, Texas, will give opinions as to certain other matters relating to the offering, including the tax opinion described in the section of this prospectus captioned “United States Federal Income Tax Considerations.” Certain legal matters in connection with the trust units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

Certain information appearing in this registration statement regarding the December 31, 2010 and September 30, 2011 estimated quantities of reserves of PCEC, the Underlying Properties and the Net Profits Interests owned by the trust, the future net revenues from those reserves and their present value is based on estimates of the reserves and present values prepared by or derived from estimates prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers.

The PCEC financial statements as of December 31, 2010 and 2009 and for each of the two years in the period ended December 31, 2010 and the period from August 26, 2008 to December 31, 2008 and the PCEC predecessor financial statements for the period from January 1, 2008 to August 25, 2008 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The Statement of Assets and Trust Corpus of the Pacific Coast Oil Trust as of January 3, 2012 included in this prospectus, has 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.

WHERE YOU CAN FIND MORE INFORMATION

The trust and PCEC have filed with the SEC in Washington, D.C. a registration statement, including all amendments, under the Securities Act relating to the trust units. As permitted by the rules and regulations of the SEC, this prospectus does not contain all of the information contained in the registration statement and the exhibits and schedules to the registration statement. You may read and copy the registration statement at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at the address in the previous sentence. To obtain information on the operation of the public reference room you may call the SEC at (800) SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. The trust’s and PCEC’s registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

The trustee intends to furnish the trust unitholders with annual reports containing the trust’s audited consolidated financial statements and to furnish or make available to the trust unitholders quarterly reports containing the trust’s unaudited interim financial information for the first three fiscal quarters of each of the trust’s fiscal years.

 

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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this prospectus the following terms have the meanings specified below.

API—The specific gravity or density of oil expressed in terms of a scale devised by the American Petroleum Institute.

Bbl—One stock tank barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.

Bbl/d—Bbl per day.

Boe—One stock tank barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals six Mcf of natural gas.

Boe/d—Boe per day.

Btu—A British Thermal Unit, a common unit of energy measurement.

Completion—The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development Well—A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential—The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil price, and the wellhead price received.

Estimated future net revenues—Also referred to as “estimated future net cash flows.” The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

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

MBbl—One thousand barrels of crude oil or condensate.

MBoe—One thousand barrels of oil equivalent.

Mcf—One thousand cubic feet of natural gas.

MMBbl—One million barrels of crude oil or condensate.

MMBoe—One million barrels of oil equivalent.

MMBtu—One million British Thermal Units.

MMcf—One million cubic feet of natural gas.

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

 

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Net profits interest—A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

Net revenue interest—An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, net profits interests, carried interests, reversionary interests and any other burdens to which the person’s interest is subject.

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

Plugging and abandonment—Activities to remove production equipment and seal off a well at the end of a well’s economic life.

Proved developed reserves—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods and includes both proved developed producing and proved developed non-producing reserves.

Proved reserves—Under SEC rules for fiscal years ending on or after December 31, 2009, proved reserves are defined as:

Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Under SEC rules for fiscal years ending prior to December 31, 2009, proved reserves are defined as:

The estimated quantities of crude 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, i.e., prices and costs as of the date the estimate is made. Prices include consideration of

 

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changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. 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 (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) 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. Reserves which 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. Estimates of proved reserves do not include the following: (A) Oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil and natural gas, that may occur in undrilled prospects; and (D) crude oil and natural gas, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved undeveloped reserves—Proved 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.

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

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

Working interest—The right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

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

 

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INDEX TO FINANCIAL STATEMENTS OF PACIFIC COAST OIL TRUST

 

PACIFIC COAST OIL TRUST:

  

Report of Independent Registered Public Accounting Firm

     F-2   

Statement of Assets and Trust Corpus as of January 3, 2012

     F-3   

Notes to Statement of Assets and Trust Corpus

     F-4   

Unaudited Pro Forma Financial Statements:

     F-6   

Introduction

     F-6   

Unaudited Pro Forma Statement of Assets and Trust Corpus as of September 30, 2011

     F-7   

Unaudited Pro Forma Statement of Distributable Income for the Nine Months Ended September  30, 2011 and for the Year Ended December 31, 2010

     F-8   

Notes to Unaudited Pro Forma Financial Statements

     F-9   

The audited financial statements of PCEC can be found beginning on page PCEC F-1.

 

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Report of Independent Registered Public Accounting Firm

To the Unitholder of Pacific Coast Oil Trust

We have audited the accompanying statement of assets and trust corpus of Pacific Coast Oil Trust as of January 3, 2012. This financial statement is the responsibility of the Trust’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 statement of assets and trust corpus is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of assets and trust corpus. An audit also includes 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.

As described in Note 2, this financial statement was prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the assets and trust corpus of Pacific Coast Oil Trust as of January 3, 2012, on the basis of accounting described in Note 2.

/s/ PricewaterhouseCoopers LLP

Los Angeles, California

January 6, 2012

 

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Pacific Coast Oil Trust

 

Statement of Assets and Trust Corpus

 

 
     January 3, 2012  

TRUST CORPUS

  

Receivable from PCEC

   $ (10

Trust Corpus

     10   
  

 

 

 

Total Trust Corpus

   $ 0   
  

 

 

 

The accompanying notes are an integral part of this financial statement.

 

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Notes to Statement of Assets and Trust Corpus

Note 1. Organization of the Trust

Pacific Coast Oil Trust (the “Trust”) is a Delaware statutory trust formed in January 2012 under the Delaware Statutory Trust Act pursuant to a Trust Agreement among Pacific Coast Energy Company LP (“PCEC”), as trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and Wilmington Trust, National Association, as Delaware Trustee (the “Delaware Trustee”). The initial contribution to the Trust was $10.

The Trust was created to acquire and hold net profits interests (the “Net Profits Interests”) for the benefit of the Trust unitholders pursuant to an agreement among PCEC, the Trustee and the Delaware Trustee. In connection with the closing of the initial public offering of trust units, PCEC intends to convey the Net Profits Interests to the Trust in exchange for trust units. The Net Profits Interests represent undivided interests in underlying properties consisting of PCEC’s interests in its oil and natural gas properties located onshore in California (the “Underlying Properties”).

The Net Profits Interests are passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, costs relating to the operation of the Underlying Properties. The Net Profits Interests will entitle the trust to receive 80% of the net profits from the sale of oil and natural gas production from proved developed reserves on the Underlying Properties as of September 30, 2011 and 25% of the net profits from the sale of oil and natural gas production from the remaining Underlying Properties.

In connection with the closing of this offering, the trust will enter into an operating and services agreement with PCEC pursuant to which PCEC will provide the Trust with certain operating and informational services relating to the Net Profits Interests in exchange for a monthly fee. The monthly fee will be an amount equal to $1.00 per Boe sold net to the trust, which fee will change on an annual basis commencing on April 1, 2013, based on changes to the United States Consumer Price Index (the “CPI”).

The Trustee can authorize the Trust to borrow money to pay trust administrative or incidental expenses that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from the Trustee as a lender provided the terms of the loan are fair to the trust unitholder and similar to the terms it would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. The Trustee may also deposit funds awaiting distribution in an account with itself, if the interest paid to the Trust at least equals amounts paid by the Trustee on similar deposits, and make other short-term investments with the funds distributed to the Trust.

Note 2. Trust Significant Accounting Policies

(a) Basis of Accounting

The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interests and payments of expenses incurred. The Net Profits Interests represent the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties plus certain offsets. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the conveyance creating the Net Profits Interests.

The financial statements of the Trust, as prepared on a modified cash basis, reflect the Trust’s assets, liabilities, Trust corpus, earnings and distributions as follows:

 

  (i) Income from Net Profits Interests are recorded when distributions are received by the Trust;

 

  (ii) Distributions to Trust unitholders are recorded when paid by the Trust;

 

  (iii) Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid;

 

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  (iv) PCEC operating and services fee is recorded when paid; and

 

  (v) Cash reserves for Trust expenses may be established by the Trustee for certain expenditures that would not be recorded as contingent liabilities under accounting principles generally accepted in the United States of America (“GAAP”).

Amortization of the investment in Net Profits Interests are calculated on a unit-of-production basis and are charged directly to Trust corpus. Such amortization does not affect cash earnings of the Trust.

Investment in the Net Profits Interests is periodically assessed to determine whether its aggregate value has been impaired below its total capitalized cost based on the Underlying Properties. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value. Fair value is generally determined from estimated discounted cash flows.

While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

To date, the Net Profits Interests have not been conveyed by PCEC to the Trust. Thus, there have been no receipts from the Net Profits Interests and no trust general and administrative expenses nor fees for PCEC operating and services have been incurred.