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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

for the quarterly period ended June 30, 2012

OR

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

for the transition period from                  to                 

Commission File Number: 1-35532

PACIFIC COAST OIL TRUST

(Exact name of registrant as specified in its charter)

1-800-852-1422

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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):

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

As of August 13, 2012, 38,583,158 Units of Beneficial Interest in Pacific Coast Oil Trust were outstanding.

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FORWARD-LOOKING STATEMENTS

This Form 10-Q contains “forward-looking statements” about Pacific Coast Oil Trust (the “Trust”) and its sponsor, Pacific Coast Energy Company LP, a privately held Delaware partnership (“PCEC”), that are subject to risks and uncertainties. All statements other than statements of historical fact included in this Form 10-Q, including, without limitation, statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” are forward-looking statements.  When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-Q, 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, including the failure to obtain necessary discretionary permits;

· the effect of changes in commodity prices or 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 Form 10-Q. The Trust does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this Form 10-Q or to reflect the occurrence of unanticipated events, unless required by law.

This Form 10-Q describes other important factors that could cause actual results to differ materially from expectations of PCEC and the Trust, including under “Risk Factors” in Section 1A of Part II hereof.  All written and oral forward-looking statements attributable to PCEC or 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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GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this report 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.

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.

Overriding royalty interest—A fractional, undivided interest or right of participation in the oil or gas, or in the proceeds from the sale of oil and gas, that is limited in duration to the term of an existing lease and that is not subject to the expenses of development, operation or maintenance.

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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—Proved reserves that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate.

Proved reserves—The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be economically producible in future years from known reservoirs under existing economic and operating conditions and government regulations. 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. This definition of proved reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

Proved undeveloped reserves or PUDs—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. This definition of proved undeveloped reserves has been abbreviated from the applicable definitions contained in Rule 4-10(a)(2-4) of Regulation S-X.

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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PART I—FINANCIAL INFORMATION

Item 1.  Financial Statements.

PACIFIC COAST OIL TRUST

Statement of Assets and Trust Corpus

(unaudited)

The accompanying notes are an integral part of these financial statements.

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PACIFIC COAST OIL TRUST

Statements of Distributable Income

(unaudited)

The accompanying notes to financial statements are an integral part of these statements.

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PACIFIC COAST OIL TRUST

Statements of Changes in Trust Corpus

(unaudited)

The accompanying notes to financial statements are an integral part of these financial statements.

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PACIFIC COAST OIL TRUST

NOTES TO FINANCIAL STATEMENTS

(Unaudited)

Note 1.   Organization of the Trust

Formation 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 Agreement was amended and restated by PCEC, the Trustee and the Delaware Trustee on May 8, 2011. References in this report to the “Trust Agreement” are to the amended and restated trust agreement.

The Trust was created to acquire and hold net profits and royalty interests in certain oil and natural gas properties located in California (the “Conveyed Interests”) for the benefit of the Trust unitholders pursuant to an agreement among PCEC, the Trustee and the Delaware Trustee. The Conveyed 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 Conveyed Interests were conveyed by PCEC to the Trust concurrent with the initial public offering of the Trust’s common units in May 2012.

The Conveyed 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 Conveyed Interests 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 December 31, 2011 and either a 25% net profits interest from the sale of oil and natural gas production from all other development potential on the Underlying Properties (the “Remaining Properties”) or a 7.5% royalty interest from the sale of oil and natural gas production from the Remaining Properties located in PCEC’s Orcutt properties (the “Royalty Interest Proceeds”).

The Trust calculates the net profits and royalties for the Developed Properties and Remaining Properties monthly.  For any monthly period during which costs for the Remaining Properties exceed gross proceeds, the Trust will be entitled to receive the Royalty Interest Proceeds, and the Trust would continue to receive such proceeds until the first day of the month following the day on which cumulative gross proceeds for the Remaining Properties exceed the cumulative total excess costs for the Remaining Properties (herein referred to as an “NPI Payout”).  Due to significant planned capital expenditures associated with the Remaining Properties for the benefit of the Trust, PCEC expects the Trust to receive payments associated with the Remaining Properties in the form of Royalty Interest Proceeds until the NPI Payout occurs in approximately 2020.  In any monthly period following an NPI Payout, the Trust is entitled to receive Royalty Interest Proceeds if costs for the Remaining Properties exceed gross proceeds.

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 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.

Conveyance of Net Profits Interest and Overriding Royalty Interest and Initial Public Offering

On May 8, 2012, the Trust and PCEC entered into a Conveyance of Net Profits Interests and Overriding Royalty Interest (the “Conveyance”), pursuant to which PCEC conveyed to the Trust the Net Profits Interest and the Royalty Interest, which are collectively referred to herein as the “Conveyed Interests”.

Concurrent with the Conveyance, PCEC sold 18,500,000 Trust Units to the public in an initial public offering (“IPO”).  The proceeds (net of underwriting discounts of approximately $23 million) received by PCEC (before expenses) from the sale of 18,500,000 Trust Units were approximately $346.9 million. The Trust received no proceeds from the sale of the Trust Units.  The IPO is described in the final Prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b)(1) on May 4, 2012 (the “Prospectus”).  Upon completion of the offering, there were 38,583,158 Trust Units issued and outstanding, of which PCEC owned 20,083,158 Trust Units, or 52% of the issued and outstanding Trust Units.

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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 Conveyed 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. The Royalty Interest represents the right to receive revenues (oil and natural gas sales), less production and operating taxes and post-production costs. 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 Conveyed 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 the Conveyed Interests is 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 include the Trustee’s fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid;

(iv)              PCEC’s 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”).

The initial carrying value of the net profits interests was PCEC’s historical net book value of the interests on May 8, 2012, the date of transfer to the Trust, except for the commodity derivatives which are reflected at their fair value as of May 8, 2012.

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

Investment in the Conveyed 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.

The Conveyed Interests were conveyed by PCEC to the Trust on May 8, 2012. During the three months ended March 31, 2012, no payments from the Conveyed Interests were received, no Trust general and administrative expenses were paid and no operating and services fees to PCEC were incurred.

The accompanying unaudited interim financial statement should be read in conjunction with the audited financial statements and notes thereto of the Trust included in the Prospectus.

(b) Use of Estimates

The preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Note 3.   Income Taxes

Tax counsel to the Trust advised the Trust at the time of formation that for U.S. federal income tax purposes, the Trust will be treated as a grantor Trust and will not be subject to tax at the Trust level. Consistent with that advice, 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

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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.

Note 4.   Commodity Derivative Contracts

PCEC has entered into commodity derivative contracts with Wells Fargo Bank, National Association in order to mitigate the effects of falling commodity prices through March 31, 2014. These contracts also limit the amount of cash available for distribution if prices increase above the fixed hedge price. The Trust will be entitled to the effect of 2,000 barrels of daily swap volumes of Brent crude oil at $115.00 per barrel during the twenty-four months ending March 31, 2014, which represents approximately 70% of expected oil production from April 1, 2012 through March 31, 2014 from the proved developed reserves as of December 31, 2011, proportional to the Trust’s interest in the Developed Properties.

The amounts received by PCEC from the commodity derivative contract counterparty upon settlement of the commodity derivative contracts will reduce the operating expenses related to the Underlying Properties in calculating the Net Profits Interests. In addition, the aggregate amounts paid by PCEC on settlement of the commodity derivative contracts related to the Underlying Properties will reduce the amount of the Net Profits Interests paid to the Trust.

Note 5.   Net Profits Interests and Overriding Royalty Interest

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 conveyance 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 will be paid to the Trust on or before the eighth business day after the last business day of the following month. For any monthly period during which costs for the Remaining Properties exceed gross proceeds, the Trust would be entitled to receive the Royalty Interest Proceeds and the Trust would continue to receive such proceeds until the first day of the month following an NPI Payout. In calendar months following an NPI Payout, 25% of the net profits from the sale of oil and natural gas production from all of the Remaining Properties will be paid to the Trust on or before the end of the following month.

“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 (including, with respect to the Remaining Properties, the Royalty Interest, to the extent paid), as described in the conveyance), 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 conveyance):

·                  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 conveyance 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 conveyance, as further described in the conveyance);

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

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

Costs deducted in the net profits determination will be reduced by certain offset amounts. The offset amounts are further described in the conveyance, 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 will be deducted from gross profits for the Developed 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 would be entitled to receive the Royalty Interest Proceeds.

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.

Overriding Royalty Interest

For any monthly period during which costs for the Remaining Properties exceed gross proceeds, the Trust would be entitled to receive an amount equal to 7.5% of the proceeds attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt properties, including but not limited to PCEC’s interest in such production (free of any production or development costs but bearing its proportionate share of production and property taxes and post-production costs) (the “Royalty Interest”).

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Proceeds from the sale of oil, natural gas liquids and natural gas production from the Remaining Properties located on PCEC’s Orcutt properties in any calendar month means the amount calculated based on actual sales volumes from such properties, in each case after deducting the Trust’s proportionate share of:

·                  any taxes levied on the severance or production of the oil, natural gas liquids and natural gas produced from such properties and any property taxes attributable to the oil, natural gas liquids and natural gas produced from the such properties; and

·                  post-production costs, which will generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market the oil, natural gas liquids and natural gas produced, as applicable (excluding costs for marketing services provided by PCEC).

Proceeds payable to the Trust from the sale of oil, natural gas liquids and natural gas production attributable to the Remaining Properties located on PCEC’s Orcutt properties in any calendar month are not subject to any deductions for any expenses attributable to exploration, drilling, development, operating, maintenance or any other costs incident to the production of oil, natural gas liquids and natural gas attributable to such properties, including any costs to drill, complete or plug and abandon a well. Additionally, costs associated with any completion activities will be borne by PCEC or any third-party operator of the well.

Note 6.   Distributions to Unitholders

Each month, beginning with May 2012, the Trustee determines 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 Conveyed 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, subject to adjustments for changes made by the Trustee during the month in any cash reserves established for future liabilities of the Trust. Distributions are made to the holders of Trust units as of the applicable record date (generally the last business day of each calendar month) and are payable on or before the 10th business day after the record date. The following table illustrates information regarding the Trust’s distributions paid during the three months ended June 30, 2012. During the three months ended March 31, 2012, there were no distributions.

Three Months Ended June 30, 2012

Note 7.   Related Party Transactions

Trustee Administrative Fee.  Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the Trustee and $2,000 to the Delaware Trustee. During the three and six months ended June 30, 2012, the Trust paid $0 and $60,000 , respectively, to the Trustee and $0 and $3,500, respectively, to the Delaware Trustee.

PCEC Operating and Services Fee.  On May 8, 2012, the Trust and PCEC entered into an Operating and Services Agreement (the “Operating and Services Agreement”), pursuant to which PCEC will provide the Trust with certain operating and informational service relating to the Conveyed Interests in exchange for a monthly fee. The PCEC operating and services fee will be charged monthly in an amount equal to $83,333.33, which fee will change on an annual basis commencing on April 1, 2013, based on changes to the Consumer Price Index. The PCEC operating and services agreement will terminate upon the termination of the Conveyed Interests unless earlier terminated by mutual agreement of the trustee and PCEC.

During the three months ended June 30, 2012 the Trust paid PCEC $83,333.33.  There were no payments to PCEC under the Operating and Services Agreement during the three months ended March 31, 2012.

Initial Public Offering.  On May 8, 2012, PCEC sold 18,500,000 Trust Units to the public in connection with the IPO.  The proceeds (net of underwriting discounts of approximately $23 million) received by PCEC (before expenses) from the IPO were approximately $346.9 million.  The Trust received no proceeds from the sale of the Trust Units.  The offering is further described in the Prospectus filed on May 4, 2012.  In connection with the IPO, the Trust entered into the Operating and Services Agreement, the Registration Rights Agreement and the other agreements and instruments described herein and in the Prospectus.

Registration Rights Agreement.  On May 8, 2012, the Trust and PCEC entered into a Registration Rights Agreement (the “Registration Rights Agreement”) pursuant to which PCEC, its affiliates and any transferee of PCEC’s Trust Units will be entitled, beginning 180 days after the date of the Registration Rights Agreement, to demand that the Trust use its reasonable best efforts to

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effect the registration of such holders’ Trust Units under the Securities Act.  The holders are entitled to demand a maximum of five such registrations.  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.

Note 8.   Funding Commitment and Letter of Credit

PCEC has provided the Trust 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, including interest thereon, 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.

Note 9.   Subsequent Events

On July 16, 2012, the distribution of $0.15392 per Trust Unit, which was declared on June 19, 2012, was paid to Trust unitholders owning Trust Units as of June 29, 2012.

On July 20, 2012, the Trust declared a distribution of $0.15187 per unit to unitholders of record as of July 31, 2012.  The distribution is payable to Trust unitholders on August 14, 2012.

Item 2.    Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

Introduction.

The Trust is a statutory trust formed in January 2012 under the Delaware Statutory Trust Act. The business and affairs of the Trust are managed by the Trustee. The Trust’s purpose is to hold the Conveyed Interests (described below), to distribute to the Trust unitholders cash that the Trust receives in respect of the Conveyed Interests, subject to the effects of the commodity derivative contracts described in Note 4 to the financial statements contained in Part I, Item 1 of this Quarterly Report, and to perform certain administrative functions in respect of the Conveyed Interests and the Trust units. The Trust does not conduct any operations or activities. The Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties. Wilmington Trust, National Association, as the Delaware Trustee (the “Delaware Trustee”), has only minimal rights and duties as are necessary to satisfy the requirements of the Delaware Statutory Trust Act.  The Trust derives all or substantially all of its income and cash flow from the Conveyed Interests, subject to the effects of the commodity derivative contracts. The Trust is treated as a grantor trust for U.S. federal income tax purposes.

The Trust was created to acquire and hold net profits and royalty interests in certain oil and natural gas properties located in California and further described below for the benefit of the Trust unitholders pursuant to an agreement among Pacific Coast Energy Company, LP, a privately-held Delaware limited partnership (“PCEC”), the Trustee and the Delaware Trustee. The Conveyed Interests (as defined below) 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 Conveyed Interests were conveyed by PCEC to the Trust concurrent with the initial public offering of the Trust’s common units in May 2012.

Concurrent with the initial public offering, on May 8, 2012, the Trust and PCEC entered into a Conveyance of Net Profits Interests and Overriding Royalty Interest (the “Conveyance”), pursuant to which PCEC conveyed to the Trust net profits interest and an overriding royalty interest (the “Conveyed Interests”) in certain oil and natural gas properties in California (the “Underlying Properties”). The Conveyed Interests entitle the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the proved developed reserves as of December 31, 2011 on the Underlying Properties (the “Developed Properties”) and either 25% of the net profits from the sale of oil and natural gas production from all other development potential on the Underlying Properties (the “Remaining Properties”) or a 7.5% royalty interest from the sale of oil and natural gas production from the Remaining Properties located in PCEC’s Orcutt properties (the “Royalty Interest Proceeds”).

The Trust calculates the net profits and royalties for the Developed Properties and Remaining Properties monthly.  For any monthly period during which costs for the Remaining Properties exceed gross proceeds, the Trust would be entitled to receive the

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Royalty Interest Proceeds, and the Trust would continue to receive such proceeds until the first day of the month following the day on which cumulative gross proceeds for the Remaining Properties exceed the cumulative total excess costs for the Remaining Properties (such occurrence being herein called an “NPI Payout”).  Due to significant planned capital expenditures associated with the Remaining Properties for the benefit of the Trust, PCEC expects the Trust to receive payments associated with the Remaining Properties in the form of Royalty Interest Proceeds until the NPI Payout occurs in approximately 2020.  In any monthly period following an NPI Payout, the Trust is entitled to receive Royalty Interest Proceeds if costs for the Remaining Properties exceed gross proceeds.

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.  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 a unitholder’s original investment. Oil and natural gas production from proved reserves attributable to the Underlying Properties will decline over time.

Properties.

The Underlying Properties consist of (i) the proved developed reserves as of December 31, 2011 on the Underlying Properties (the “Developed Properties,”) and (ii) all other development potential on the Underlying Properties (the “Remaining Properties”).  Production from the Developed Properties that will be attributable to the Trust is produced from wells that, because they have already been drilled, require limited additional capital expenditures. Production from the Remaining Properties that will be attributable to the Trust will require capital expenditures for the drilling of wells and installation of infrastructure. PCEC will supply required capital on behalf of the Trust during this period; however, because the costs initially incurred will exceed gross proceeds, the Remaining Properties will have negative net profits during the drilling and development period. During this period of negative net profits, instead of being paid net profits, the Trust will be paid a 7.5% overriding royalty on the portion of the Remaining Properties located on PCEC’s Orcutt properties. Once revenues from the Remaining Properties have paid back PCEC for the cumulative costs it has advanced on behalf of the Trust, the net profits interests on the Remaining Properties will be paid out in place of the royalty interests, as described below. The net profits interests and royalty interest conveyed to the Trust are referred to herein as the “Net Profits Interests” and “Royalty Interest,” respectively. These interests, collectively the “Conveyed Interests,” entitle the Trust to receive the following:

Developed Properties

·                  80% of the net profits from the sale of oil and natural gas production from the Developed Properties.

Remaining Properties

·                  7.5% of the proceeds (free of any production or development costs but bearing the proportionate share of production and property taxes and post-production costs) attributable to the sale of all oil and natural gas production from the Remaining Properties located on PCEC’s Orcutt properties, including but not limited to PCEC’s interest in such production (the “Royalty Interest Proceeds”), or

·                  25% of the net profits from the sale of oil and natural gas production from all of the Remaining Properties.

The Trust calculates the net profits and royalties for the Developed Properties and the Remaining Properties separately. Any excess costs for either the Developed Properties or the Remaining Properties will not reduce net profits calculated for the other. The amount of Royalty Interest Proceeds paid will be taken into account in the net profits interest calculation for the Remaining Properties. If at any time cumulative costs for the Developed Properties or the Remaining Properties exceed cumulative gross proceeds associated with such properties, neither the Trust nor the Trust unitholders would be liable for the excess costs, but the Trust would not receive any net profits from the Developed Properties or the Remaining Properties, as the case may be, until future cumulative net profits for such properties exceed the cumulative total excess costs for such properties.

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. In addition, from and after April 1, 2012, if the Remaining Properties are not entitled to a share of such net profits because costs exceed gross profits, the Royalty Interest will be entitled to the Royalty Interest Proceeds until the NPI Payout occurs.

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 Trust will dissolve upon the earliest to occur of the following: (1) the Trust, upon approval of the holders

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of at least 75% of the outstanding Trust units, sells the Net Profits Interest, (2) the annual cash available for distribution to the Trust is less than $2 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.

Commodity Derivative Contracts

The revenues derived from the Underlying Properties depend substantially on prevailing oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that PCEC or the third-party operators can economically produce. PCEC has entered into hedge contracts to reduce the exposure of the revenues from oil production from the Underlying Properties to fluctuations in oil prices and to achieve more predictable cash flow. However, these contracts limit the amount of cash available for distribution if prices increase above the fixed hedge price.  None of the Trust’s exposure to natural gas prices is hedged.

PCEC has entered into commodity derivative contracts with Wells Fargo Bank, National Association in order to mitigate the effects of falling commodity prices through March 31, 2014. The Trust will be entitled to the effect of 2,000 barrels of daily swap volumes of Brent crude oil at $115.00 per barrel during the twenty-four months ending March 31, 2014, which represents approximately 70% of expected oil production from April 1, 2012 through March 31, 2014 from the proved developed reserves as of December 31, 2011, proportional to the Trust’s interest in the Developed Properties.

The Trust will not bear any commodity derivative settlement costs paid by PCEC, or be entitled to any commodity derivative payments received by PCEC, for periods prior to April 2012.

The amounts received by PCEC from the commodity derivative contract counterparty upon settlement of the commodity derivative contracts will reduce the operating expenses related to the Underlying Properties in calculating net profits. In addition, the aggregate amounts paid by PCEC upon settlement of the commodity derivative contracts related to the Underlying Properties will reduce the amount of net profits paid to the Trust.

Results of Operations for the Three and Six Months Ended June 30, 2012

For the quarter ended June 30, 2012, income from net profits interests received by the Trust amounted to $6,549,861.  As the Trust was not formed until January 1, 2012 and the conveyance of the Net Profits Interest and Overriding Royalty Interest was not completed until May 8, 2012, the Trust did not receive or disburse funds during the quarter ended March 31, 2012.  The net profits income received by the Trust during the quarter ended June 30, 2012 was primarily associated with net profits for oil and natural gas production during the month of April 2012.  The following table displays PCEC’s underlying sales volumes and average prices for the Underlying Properties, representing the amounts included in the net profits calculation for distributions paid during the second quarter of 2012.

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Computation of Net Profits and Royalty Income Received by the Trust

The Trust’s net profits and royalty income consists of monthly net profits and royalty income attributable to the Conveyed Interests.  Net profits and royalty income income for the three months ended June 30, 2012 was determined as shown in the following table.  The Trust did not receive any income for the three months ended March 31, 2012.

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Excess of revenues over direct operating expenses and development expenses from the Underlying Properties was approximately $8.7 million for the three months ended June 30, 2012.  There were no exess revenues associated with the Overriding Royalties for the three months ended June 30, 2012.  Applying the net profits interest percentage of 80% to the excess of reveues over direct operating expenses and development expenses results in income from the Net Profits Interest to the Trust of approximately $7.0 million.  Settlement payments of approximately $327,360 related to hedge contracts and PCEC’s Operating and Service Fee of $83,333 results in income from the Net Profits Interest to the Trust of approximately $6.6 million.

The Trustee paid general and administrative expenses of $236,390 during the second quarter of 2012.  Expenses paid during the second quarter primarily consisted of legal fees associated with the formation of the Trust.  The Trust withheld $50,000 as a reserve for future Trust expenses during the quarter, resulting in distributable income of approximately $6.3 million.

Total capital expenditures included in the net profits calculation during the quarter ended June 30, 2012 were $74,000.

Total lease operating expenses included in the net profits calculation during the second quarter of 2012 were approximately $3.2 million.

Liquidity and Capital Resources

Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to Trust unitholders.  Available funds are the excess cash, if any, received by the Trust from the Conveyed Interests and other sources (such as interest earned on any amounts reserved by the Trustee) in that month, over the Trust’s expenses paid for that month.  Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses.

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 Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. If the Trustee causes the Trust to borrow funds, the Trust unitholders will not receive distributions until the borrowed funds are repaid. As of June 30, 2012 the Trust has reserved $50,000 for future Trust expenses.

Each month, the Trustee will pay Trust obligations and expenses and distribute to the Trust unitholders the remaining proceeds received from the Conveyed Interests. The cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date may be invested in a limited number of permitted investments.  Alternatively, cash held for distribution at the next distribution date may be held in a noninterest bearing account.

PCEC has provided the Trust 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, including interest thereon, 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.

The Trustee has no current plans to authorize the Trust to borrow money.  During the quarter and six months ended June 30, 2012, there were no borrowings.

Distributions Paid and Declared After Quarter End

On July 16, 2012, the distribution of $0.15392 per Trust Unit, which was declared on June 19, 2012, was paid to Trust unitholders owning Trust Units as of June 29, 2012.

On July 20, 2012, the Trust declared a distribution of $0.15187 per unit to unitholders of record as of July 31, 2012.  The distribution is payable to Trust unitholders on August 14, 2012.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements and does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

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New Accounting Pronouncements

As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.

Critical Accounting Policies and Estimates

Please see Note 2 to the Trust’s Statement of Assets and Trust Corpus as of January 3, 2012 included in the Trust’s Prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b)(1) on May 4, 2012 for information regarding the Trust’s critical accounting policies and estimates.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

Commodity Price Risk.  The Trust’s most significant market risk relates to the prices received for oil and natural gas production.  The revenues derived from the Underlying Properties depend substantially on prevailing oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices also affect the amount of cash flow available for distribution to the Trust unitholders. Lower prices may also reduce the amount of oil and natural gas that PCEC or the third-party operators can economically produce.

Credit Risk.  The Trust’s most significant credit risk is the risk of the bankruptcy of PCEC.  The bankruptcy of PCEC could impede the operation of wells and the development of the proved undeveloped reserves.  Further, in the event of the bankruptcy of PCEC, if a court held that the Net Profits Interests were part of the bankruptcy estate, the Trust might be treated as an unsecured creditor with respect to the Net Profits Interests.  In addition, PCEC has entered into hedge contracts to reduce the exposure of the revenues from oil production from the Underlying Properties to fluctuations in oil prices and to achieve more predictable cash flow. These contracts also limit the amount of cash available for distribution if prices increase above the fixed hedge price. The use of the hedge contracts involves the risk that the counterparty to the hedge contracts will be unable to meet its obligations under the contracts. The hedge contracts are with Wells Fargo Bank, National Association.  All payments from the hedge contract counterparty are paid to PCEC.

Item 4.    Controls and Procedures.

The Trustee maintains disclosure controls and procedures designed to ensure that information required to be disclosed by the Trust in the reports that it files or submits under Rules 13a-15 and 15d-15 under the Securities and Exchange Act of 1934, as amended (“Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this Quarterly Report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Mike Ulrich, as Trust Officer of the Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the Trust Agreement, (ii) the Operating and Services Agreement and (iii) the Conveyance of Net Profits Interests and Overriding Royalty Interest, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by PCEC, including information relating to results of operations, the costs and revenues attributable to the Trust’s interests under the Conveyance of Net Profits Interests and Overriding Royalty Interest and other operating and historical data, plans for future operating and capital expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the Underlying Properties and the Conveyed Interests and settlements under the hedge contracts between PCEC and Wells Fargo Bank, National Association, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.

During the quarter ended June 30, 2012, there was no change in the Trustee’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trustee’s internal control over financial reporting related to the Trust. The Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of PCEC.

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PART II—OTHER INFORMATION

Item 1A.     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.

Brent crude oil prices declined from record high levels in early July 2008 of over $145.00 per Bbl to below $35.00 per Bbl in December 2008. In March 2012, Brent crude oil prices ranged from $124.55 per Bbl to $127.97 per Bbl. Henry Hub natural gas prices declined from over $13.57 per MMBtu in July 2008 to below $2.00 per MMBtu in April 2012. In March 2012, Henry Hub natural gas prices ranged from $1.98 per MMBtu to $2.44 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 or any third party operator 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 any Conveyed Interest 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

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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 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 has entered into commodity derivative contracts with an affiliate of Wells Fargo in order to mitigate the effects of falling commodity prices through March 31, 2014. The trust will be entitled to the effect of 2,000 barrels of daily swap volumes of Brent crude oil at $115.00 per barrel during the twenty-four months ending March 31, 2014. 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. The commodity derivative contracts will limit the benefit to the trust of any increase in oil prices through March 31, 2014. The trust will be required to bear the settlement costs, if any, relating to the commodity derivatives contracts regardless of whether the corresponding quantities of oil are produced or sold. The terms of the conveyance of the Conveyed Interests prohibit PCEC from entering into additional hedging arrangements burdening the trust. As a result, the amount of the cash distributions will be subject to a greater fluctuation after March 31, 2014 due to changes in oil prices.

Actual reserves and future production may be less than engineers’ 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 as summarized in the reports the trust obtains from its independent petroleum engineers. 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.

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.

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. For example, the ultimate development of future production will require additional permits. Any delays, reductions, lack of permits 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. PCEC’s plan to increase production in the Orcutt Diatomite and West Pico properties beyond the currently permitted wells will require additional permits and approvals from various state and local agencies. There can be no assurances that such permits will be issued in a timely manner or at all. Additionally, 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;

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·                  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;

·                  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, distributions to trust unitholders may be reduced. Further, 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, 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 only to receive cash distributions from the Conveyed Interests and commodity derivative contracts. 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 December 31, 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 interest 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.

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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 applicable Conveyed 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 will not receive any profits from any such transfer. Following any sale or transfer of any of the Underlying Properties, the applicable Net Profits Interest and if applicable, the Royalty Interest, will continue to burden the transferred property and net profits and royalties attributable to such transferred property will be calculated for such transferred property on a stand alone basis using the computation of net profits and royalties set forth in the conveyance related to the Conveyed Interests. PCEC may delegate to the transferee responsibility for all of PCEC’s obligations relating to the applicable Conveyed Interests on the portion of the Underlying Properties transferred.

PCEC may, without the consent of the trust unitholders, require the trust to release the Conveyed 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 Conveyed 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 Conveyed Interests being treated as an offset amount against costs and expenses.

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.

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

The net profits and royalties payable to the trust attributable to the Conveyed 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 will 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.

The Trust Agreement provides that the trust’s activities are limited to owning the Conveyed Interests and any activity reasonably related to such ownership, including activities required or permitted by the terms of the conveyance related to the Conveyed Interests. As a result, the trust is not permitted to acquire other oil and natural gas properties, net profits interests or royalties to replace the depleting assets and production attributable to the Conveyed Interests.

Because the net profits and royalties 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 Conveyed Interests may cease to produce in commercially paying quantities and the trust may, therefore, cease to receive any distributions of net profits and royalties 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 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 differentials and 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.

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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 and development 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. 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 and by the PCEC operating and services fee, which is $1,000,000 annually, subject to adjustments for changes in the CPI commencing on April 1, 2013.

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. Royalty Interest Proceeds depend on the trust’s share of production and property taxes and post-production costs, if any. If at any time cumulative costs for the Developed Properties or the Remaining Properties exceed cumulative gross proceeds associated with such properties, neither the trust nor the trust unitholders would be liable for the excess costs, but the trust would not receive any net profits from the Developed Properties or the Remaining Properties, as the case may be, until cumulative gross proceeds for such properties exceed the cumulative total excess costs for such properties.

The generation of profits and royalties 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 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 2011, 2010 and 2009, ConocoPhillips purchased 97% of PCEC’s production and currently purchases 100% of its oil production. ConocoPhillips’ purchase of oil production from the Orcutt properties is pursuant to a long-term sales contract between ConocoPhillips and PCEC, and its purchase of oil production from the Sawtelle and West Pico properties is pursuant to a month-to-month contract. 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 sell the Conveyed Interests and dissolve the trust prior to the expected termination of the trust if the holders of at least 75% of the outstanding trust units approve the sale or vote to dissolve the trust or if the cash available for distribution to the trust is less than $2.0 million for each of any two consecutive years. As a result, trust unitholders may not recover their investment.

The trustee must sell the Conveyed 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 Conveyed Interests and dissolve the trust if the cash available for distribution to the trust is 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.

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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 California Department of Conservation, Division of Oil, Gas, and Geothermal Resources, or “DOGGR.” PCEC has approval under these new regulations for its current 96-well 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 PCEC’s Diatomite properties 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 in the Orcutt field. 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. Steaming operations in several Diatomite wells had to be suspended for periods of time during 2011 while surface expressions were being investigated or changes made to nearby well configurations. 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 its 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 Diatomite properties averaged 673 Boe/d during December 2011.

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 Conveyed 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 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.

PCEC holds an aggregate of 20,083,158 trust units, subject to the exercise of the underwriters’ option to purchase additional trust units granted in connection with the initial public offering of trust units.  Except pursuant to the underwriters’ option, PCEC has agreed not to sell any trust units for a period of 180 days after May 2, 2012 unless Barclays Capital Inc. consents to a shorter period. 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.

The trading price for the trust units may not reflect the value of the Conveyed 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 Conveyed 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.

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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 Conveyed Interests in connection with a sale of a portion of the Underlying Properties to which such Conveyed Interests relates. In such an event, the trust is entitled to receive the fair market value (net of sales costs) of the Conveyed 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.

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 are 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 the trust to hold annual meetings of trust unitholders or for an annual or other periodic re-election of the trustee. The trust does not intend to hold annual meetings of trust unitholders. 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 conveyance creating the Conveyed 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 conveyance creating the Conveyed Interests. If the trustee does not take appropriate action to enforce provisions of the conveyance, 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 conveyance creating the Conveyed Interests provides that, except as set forth in the conveyance, 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 are 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.

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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. PCEC’s Orcutt and East Coyote properties are located in areas that host several endangered plant and animal species. The known presence of these endangered species may limit future operations in certain areas of the properties and will result in increased costs of development as certain procedures must be used to protect such species and costs may be incurred to provide habitat areas or substitute replacement areas.

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 many 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 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 and royalties attributable to the Conveyed 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 its 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 indirectly bears 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.

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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 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 Conveyed 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. The County of Santa Barbara also recently considered imposing a severance tax. Although the proposals have not passed, 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 its 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 increased 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 has considered legislation that, if adopted, 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 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

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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 and royalties attributable to the Conveyed 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 and royalties attributable to the Conveyed Interests and, as a result, the trust’s cash available for distribution.

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 Conveyed 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. PCEC is not a reporting company and is not required to file periodic reports with the SEC pursuant to the Securities Exchange Act of 1934, as amended, or the “Exchange Act.” Therefore, neither the trust unitholders nor the Trustee 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 would 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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In the event of the bankruptcy of PCEC, if a court held that the Net Profits Interests were part of the bankruptcy estate, the trust may be treated as an unsecured creditor with respect to the Net Profits Interests.

PCEC and the trust believe that the Net Profits Interests would be treated as an interest in real property under the laws of the State of California. While no California case has defined the nature of a “net profits interest,” the California Supreme Court has held that an overriding royalty interest in an oil and gas lease (such as the Royalty Interest) is an interest in real property. The California Supreme Court has also explained that the nature of the interest created depends upon the intention of the parties involved. Given that the Net Profits Interests are defined in the conveyance as an overriding royalty interest payable on the basis of net profits and the conveyance states that it is the express intent of the parties that the Net Profits Interests constitute, for all purposes, an interest in real property, it is likely that a California court would hold that the Net Profits Interests are an interest in real property. Nevertheless, the outcome is not certain because there is no dispositive California Supreme Court case directly concluding that a conveyance of a “net profits interest” constitutes the conveyance of a real property interest. As such, in a bankruptcy of PCEC, the Net Profits Interests might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of PCEC, in which case the trust would be an unsecured creditor of PCEC at risk of losing the entire value of the Net Profits Interests to senior creditors.

Due to the trust’s lack of geographic and industry 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.

Pursuant to the recently enacted JOBS Act, the trust’s independent registered public accounting firm will not be required to attest to the effectiveness of the trust’s internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as the trust is an emerging growth company and the trust may take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards.

The trust will be required to disclose changes made in its internal control over financial reporting on a quarterly basis and the trustee will be required to assess the effectiveness of the trust’s controls annually. However, for as long as the trust is an “emerging growth company” under the recently enacted JOBS Act, its independent registered public accounting firm will not be required to attest to the effectiveness of the trust’s internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. The trust could be an emerging growth company for up to five years.  Even if the trustee concludes that the trust’s internal controls over financial reporting are effective, the trust’s independent registered public accounting firm may still decline to attest to the trustee’s assessment or may issue a report that is qualified if it is not satisfied with the trust’s controls or the level at which the trust’s controls are documented, designed, operated or reviewed, or if it interprets the relevant requirements differently.

In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The trust is electing to delay such adoption of new or revised accounting standards, and as a result, the trust may not comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. As a result of such election, the trust’s financial statements may not be comparable to the financial statements of other public companies. The trust may take advantage of these reporting exemptions until it is no longer an “emerging growth company.” Neither PCEC nor the trust can predict if investors will find the trust units less attractive because the trust will rely on these exemptions. If some investors find the trust units less attractive as a result, there may be a less active trading market for the trust units and the trust’s trading price may be more volatile.

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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 trustee intends to request such a ruling or 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 and should consult with their tax advisors.

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 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.

Unitholders will be required to pay taxes on their share of the trust’s income even if they 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, unitholders will be required to pay any federal and applicable California income taxes and, in some cases, other state and local income taxes on their share of the trust’s taxable income even if they receive no cash distributions from the trust. A unitholder may not receive cash distributions from the trust equal to such unitholder’s 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 a unitholder sells trust units, the unitholder will recognize a gain or loss equal to the difference between the amount realized and the unitholder’s 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. Potential investors should consult with their tax advisors prior to acquiring Trust units. Please see “United States Federal Income Tax Considerations—Tax Consequences to U.S. Trust Unitholders—Disposition of Trust Units” in the Prospectus for additional information.

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.

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As a result of investing in trust units, unitholders 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.

PCEC has received a two-year waiver from the State of California of the requirement to withhold 7% of the amounts paid to the trust that are attributable to the Conveyed Interests held by unitholders not qualifying for an exemption for withholding, and will use its commercially reasonable efforts to maintain such waiver, including by seeking a renewal of such waiver prior to its expiration under California law. There can be no assurances, however, that PCEC will be able to obtain such a waiver in the future and, in such a case, PCEC may be required to withhold such amounts.

Item 6.                                 Exhibits.

The exhibits listed in the accompanying index are filed as part of this Quarterly Report on Form 10-Q.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

Date: August 13, 2012

The Registrant, Pacific Coast Oil Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that any such function exists pursuant to the terms of the Trust Agreement under which it serves.

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Exhibit Index

*Filed herewith.

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