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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

for the quarterly period ended September 30, 2013

OR

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 November 7, 2013, 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 those referred to 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.

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.

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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.

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

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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

Statements of Assets and Trust Corpus

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 are an integral part of these financial statements.

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PACIFIC COAST OIL TRUST

Statements of Changes in Trust Corpus

(unaudited)

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

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NOTES TO FINANCIAL STATEMENTS

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 Trust Agreement was amended and restated by PCEC, the Trustee and the Delaware Trustee on May 8, 2012. 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 (“IPO”) 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, Overriding Royalty Interest and Public Offerings

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 as the Conveyed Interests.

Concurrent with the Conveyance, PCEC sold 18,500,000 Trust units to the public in an initial public offering.  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.

On September 19, 2013, the Trust, PCEC and the other persons or entities parties signatory thereto (collectively with PCEC, the “Selling Unitholders”) entered into an Underwriting Agreement (the “Underwriting Agreement”), with the

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underwriters named therein (the “Underwriters”), with respect to the offer and sale (the “Offering”) by PCEC and the other Selling Unitholders.  On September 23, 2013, PCEC distributed 11,216,661 Trust units to the Selling Unitholders.  Immediately following the distribution, the Selling Unitholders sold 8,500,000 Trust units.  Concurrently, PCEC sold additional 5,000,000 Trust units and retained 3,866,497 Trust units, or 10% of the issued and outstanding Trust units.  The Trust received no proceeds from the sales of these Trust units.

2.             Trust Significant Accounting Policies

Basis of Accounting

The accompanying Statement of Assets and Trust Corpus as of December 31, 2012, which has been derived from audited financial statements, and the unaudited interim financial statements as of and for the three months and nine months ended September 30, 2013 have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain information and disclosures normally included in annual financial statements have been condensed or omitted pursuant to those rules and regulations. Therefore, these financial statements should be read in conjunction with the financial statements and notes thereto included in the Trust’s 2012 Annual Report on Form 10-K.

In the opinion of the Trustee, the accompanying unaudited financial statements reflect all adjustments that are necessary for a fair presentation of the interim period presented and include all the disclosures necessary to make the information presented not misleading.

The preparation of financial statements requires the Trust to make estimates and assumptions that affect reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.

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:

·                  Income from the Conveyed Interests is recorded when distributions are received by the Trust;

·                  Distributions to Trust unitholders are recorded when paid by the Trust;

·                  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;

·                  PCEC’s operating and services fee is recorded when paid; and

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

The Conveyance of the Conveyed Interests to the Trust was accounted for as a transfer of properties under common control and recorded at PCEC’s historical net book value of the Conveyed Interests on May 8, 2012, the date of transfer to the Trust, except for the commodity derivatives which were 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 the Trust corpus. During the three months and nine months ended September 30, 2013 amortization expense was $5.2 million and $15.8 million, respectively. Such amortization does not affect cash earnings of the Trust.  Accumulated amortization as of September 30, 2013 and December 31, 2012 was $29.1 million and $13.3 million, respectively.

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

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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.  There was no impairment as of September 30, 2013 or December 31, 2012.

While these statements differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“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 non-GAAP basis of accounting 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.

3.             Income Taxes

Federal Income Taxes

Tax counsel to the Trust advised the Trustee at the time of formation that for U. S. federal income tax purposes, the Trust will be treated as a grantor trust and therefore will not be subject to tax at the Trust level. Trust unitholders are treated as owning a direct interest in the assets of the Trust, and each Trust unitholder is taxed directly on his pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his pro rata share of the deductions and expenses attributable to the assets of the Trust. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.

The deductions of the Trust consist primarily of administrative expenses.  In addition, each unitholder is entitled to depletion deductions because the Net Profits Interest constitutes “economic interests” in oil and gas properties for federal income tax purposes.  Each unitholder is entitled to amortize the cost of the Trust units through cost depletion over the life of the Net Profits Interest or, if greater, through percentage depletion.  Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the Trust units.  Rather, a unitholder is entitled to percentage depletion as long as the applicable Underlying Properties generate gross income.

Some Trust units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (including custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name).  Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 919 Congress Avenue, Austin, Texas 78701, telephone number (512) 236-6545, is the representative of the Trust that provides tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT.  Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements.  Unitholders whose units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust units.

The tax consequences to a unitholder of ownership of Trust units will depend in part on the unitholder’s individual tax circumstances. Unitholders should consult their tax advisors about the federal tax consequences relating to owning the Trust units.

State Taxes

The Trust’s revenues are from sources in the state of California. Because it distributes all of its net income to unitholders, the Trust should not be taxed at the trust level. California presently taxes income of nonresidents from real property located within the state.  California taxes nonresidents on royalty income from the royalties located in that state and also imposes a corporate income tax which may apply to unitholders organized as corporations.  Each unitholder should consult his or her own tax advisor regarding state tax requirements applicable to such person’s ownership of Trust units.

4.             Commodity Derivative Contracts

PCEC entered into commodity derivative contracts with Wells Fargo Bank, National Association on behalf of the Trust 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 is 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

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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 or paid by PCEC from the commodity derivative contract counterparty upon settlement of the commodity derivative contracts will reduce or increase the operating expenses related to the Underlying Properties in calculating the Net Profits Interests. The Trust received from PCEC net settlements related to derivative contracts of $1.9 million and $3.7 million, respectively, for the three months and nine months ended September 30, 2013. In addition, the Trust received from PCEC net settlements of $2.2 and $1.9 million, respectively, related to derivative contracts for the three months and nine months ended September 30, 2012.

5.             Distributions to Unitholders

Each month, 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, in excess of 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 within five business days after 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 provides information regarding the Trust’s distributions paid during the nine months ended September 30, 2013 and 2012.

Nine Months Ended September 30, 2013

Nine Months Ended September 30, 2012

6.             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 months and nine months ended September 30, 2013, the Trust paid $50,000 and $150,000 to the Trustee and $0 and $2,000 to the Delaware Trustee, respectively. During the three months and nine months ended September 30, 2012, the trust paid $50,000 and $110,000, respectively, to the Trustee and $0 and $3,500, respectively, to the Delaware Trustee.

PCEC Operating and Services Fee.  Under the terms of the Operating and Services Agreement, PCEC provides the Trust with certain operating and informational services relating to the Conveyed Interests in exchange for a monthly fee equal to $83,333, which changed to $85,083 commencing on April 1, 2013. The monthly fee will be revised annually on April 1, 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 and nine months ended September 30, 2013 the Trust paid PCEC $0.3 million and $0.8 million, respectively. During the three months and nine months ended September 30, 2012 the Trust paid PCEC $0.3 million and $0.3 million, respectively.

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Registration Rights Agreement. The Trust is party to a registration rights agreement pursuant to which the Trust has agreed, for the benefit of PCEC and any transferee of PCEC’s Trust units, to register the Trust units they hold. On June 17, 2013, pursuant to the registration rights agreement, the Trust filed a registration statement on Form S-3 registering the offering by PCEC of 20,083,158 Trust units.  The registration statement was declared effective on September 12, 2013.

Underwriting Agreement. On September 19, 2013, the Selling Unitholders entered into an Underwriting Agreement with the Underwriters, with respect to the offer and sale (the “Secondary Offering”) by the Selling Unitholders of 13,500,000 Trust units at a price of $17.10 per Trust Unit ($16.416 per Trust unit, net of underwriting discounts and commissions). Pursuant to the Underwriting Agreement, the Selling Unitholders also granted the Underwriters an option for a period of 30 days to purchase up to an additional 2,025,000 Trust units on the same terms, which expired unexercised. On September 25, 2013, the Selling Unitholders completed the Secondary Offering under the registration statement described under Registration Rights Agreement in this Note 6. The Trust did not receive any proceeds from the Secondary Offering. Following the closing of the Secondary Offering and as of September 30, 2013, PCEC held 10% of all outstanding Trust units.

7.                                      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.  There were no borrowings outstanding at September 30, 2013.

8.                                      Subsequent Events

On October 14, 2013, the distribution of $0.15761 per Trust Unit, which was declared on September 24, 2013, was paid to Trust unitholders owning Trust units as of October 4, 2013.

On October 24, 2013 the Trust declared a distribution of $0.14756 per unit to unitholders of record as of November 7, 2013.  The distribution is payable to Trust unitholders on November 14, 2013.

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

The following review of the Trust’s financial condition and results of operations should be read in conjunction with the financial statements and notes thereto, as well as the Trustee’s Discussion and Analysis of Financial Condition and Results of Operations contained in the Trust’s 2012 Annual Report on Form 10-K.  The following review should also be read in conjunction with the “Cautionary Statement Regarding Forward-Looking Information” in this report and Part I — Item 1A — “Risk Factors” in the Trust’s Annual Report on Form 10-K.

Overview

The Trust is a statutory trust formed in January 2012 under the Delaware Statutory Trust Act. The business and affairs of the Trust are administered 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

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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.  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 is 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 (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 makes 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 within five business days after the last business day of each calendar month).  Distributions are payable on or before the 10th business day after the record date.  Actual cash distributions to the Trust unitholders 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 are generated by depleting assets with the production from the Underlying Properties diminishing over time, a portion of each distribution represents, 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.

Conveyance of Net Profits Interest, Overriding Royalty Interest and Public Offerings

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 as the Conveyed Interests, in exchange for 38,583,158 Trust units.

Concurrent with the Conveyance, PCEC sold 18,500,000 Trust units to the public in an initial public offering.  The Trust received no proceeds from the sale of the Trust units.  Upon completion of the Trust’s initial public offering, PCEC owned 20,083,158 Trust units, or 52% of the issued and outstanding Trust units. On September 19, 2013, the Trust, PCEC and the other persons or entities parties signatory thereto (collectively with PCEC, the “Selling Unitholders”) entered into an Underwriting Agreement (the “Underwriting Agreement”), with the underwriters named therein (the “Underwriters”), with respect to the offer and sale (the “Offering”) described therein by PCEC and the other Selling Unitholders.  On September 23, 2013, PCEC distributed 11,216,661 Trust units to the Selling Unitholders.  Immediately following the distribution, the Selling Unitholders sold 8,500,000 Trust units.  Concurrently, PCEC sold additional 5,000,000 Trust units and retained 3,866,497 Trust units, or 10% of the issued and outstanding Trust units.  The Trust did not receive any proceeds from the Secondary Offering.

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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 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 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 $2.0 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding Trust units vote in favor of dissolution or (4) the Trust is judicially dissolved.

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 commodity derivative 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 on behalf of the Trust in order to mitigate the effects of falling commodity prices through March 31, 2014. The Trust is 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

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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. 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 Months Ended September 30, 2013 and 2012

For the three months ended September 30, 2013, income from Conveyed Interests received by the Trust amounted to $18.7 million compared with $17.7 million for the three months ended September 30, 2012.  The net profits income received by the Trust during the quarter ended September 30, 2013 and 2012 were primarily associated with net profits for oil and natural gas production during the months of May, June and July of 2013 and 2012, respectively.

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 three months ended September 30, 2013 and 2012.

(a)                                 Crude oil sales represented 97% and 98% of total sales volumes from the Developed Properties for the three months ended September 30, 2013 and 2012, respectively.

(b)                                 Crude oil sales represented 100% of total sales volumes from the Remaining Properties.

Computation of Net Profits and Royalty Income Received by the Trust

The Trust’s net profits and royalty income consist of monthly net profits and royalty income attributable to the Conveyed Interests.  Net profits and royalty income for the three months ended September 30, 2013 and 2012 were 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 Developed Properties, before net settlements related to commodity derivative contracts, was approximately $20.7 million for the three months ended September 30, 2013 compared to $19.6 million for the three months ended September 30, 2012.  The increase in the excess revenue is contributed principally to higher average realized oil prices, partially offset by lower production volume. Average realized prices were approximately 4% higher while the production volume was 1% lower for the three months ended September 30, 2013 compared same period in 2012. Total capital expenditures included in the net profits calculation during the third quarter of 2013 were approximately $1.4 million compared to $0.1 million in the third quarter of 2012, reflecting higher capital development cost at Orcutt.   Total lease operating expenses included in the net profits calculation during the third quarter of 2013 were approximately $8.6 million compared with approximately $9.9 million in the 2012 third quarter.  Net settlement receipts related to commodity derivative contracts were $1.9 million for the three months ended

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September 30, 2013. Settlement receipts related to commodity derivative contracts were $2.2 million for the three months ended September 30, 2012.

For the Remaining Properties, costs exceeded gross proceeds for the three months ended September 30, 2013, therefore the Trust received approximately $0.5 million from the 7.5% Overriding Royalty attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt Properties.  The Trust received approximately $48,000 from the Remaining Properties during the third quarter of 2012.  The cumulative deficit of the net profits interest on the Remaining Properties, including the 7.5% Overriding Royalty, was approximately $3.9 million and $3.2 million, respectively at September 30, 2013 and 2012. The cumulative deficit must be repaid before the Trust will be entitled to payments under its net profits interest relating to the Remaining Properties.

PCEC charged the Trust $0.3 million and $0.3 million, respectively, for the Operating and Service Fee for the three months ended September 30, 2013 and 2012.

The total cash received by the Trust from PCEC for the three months ended September 30, 2013 was approximately $18.7 million compared to $17.7 million for the three months ended September 30, 2012.  The Trustee paid general and administrative expenses of $0.1 million during the third quarter of 2013 compared with $0.1 million during the third quarter of 2012.  Expenses paid during the 2013 third quarter consisted primarily of Trustee fees while the expenses paid during the third quarter of 2012 primarily consisted of Trustee fees, legal fees and New York Stock Exchange listing fees.  The distributable income was approximately $18.6 million and $17.5 million, respectively, for the three months ended September 30, 2013 and 2012.

Results of Operations for the Nine Months Ended September 30, 2013 and 2012

For the nine months ended September 30, 2013, income from Conveyed Interests received by the Trust amounted to $53.1 million compared with $24.2 million for the nine months ended September 30, 2012.  Because the Trust was not formed until January 3, 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 nine months ended September 30, 2012 was primarily associated with net profits for oil and natural gas production during April, May, June and July 2012. The net profits income received by the Trust during the nine months ended September 30, 2013, was primarily associated with net profits for oil and natural gas production during the months of November and December 2012 and January through July 2013.

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 nine months ended September 30, 2013 and 2012.

(a)                                 Crude oil sales represented 96% and 98% of total sales volumes from the Developed Properties for the nine months ended September 30, 2013 and 2012, respectively.

(b)                                 Crude oil sales represented 100% of total sales volumes from the Remaining Properties.

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Computation of Net Profits and Royalty Income Received by the Trust

The Trust’s net profits and royalty income consist of monthly net profits and royalty income attributable to the Conveyed Interests.  Net profits and royalty income for the nine months ended September 30, 2013 and from Inception (May 8, 2012) through September 30, 2012 were 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 Developed Properties, before net settlements related to commodity derivative contracts, was approximately $60.8 million for the nine months ended September 30, 2013 compared to $28.3 million for the nine months ended September 30, 2012, reflecting a shorter period of operation due to the May 8, 2012 inception date. The increase in the excess revenue is attributed principally to higher average realized oil prices and higher production compared to the nine months ended September 30, 2012.  Total capital expenditures included in the net profits calculation during the nine months ended September 30, 2013 were approximately $3.5 million compared to $0.2 million in the same period of 2012, reflecting higher expenditures at Orcutt, East Coyote, Sawtelle and West Pico.  Total lease operating expenses included in the net profits calculation during the nine months ended September 30, 2013 were approximately $29.1 million compared with approximately $13.1 million in the nine months ended September 30, 2012. The increase in lease operating expenses for the nine months ended September 30, 2013 primarily reflects increased well work at Orcutt.  Net settlement receipts related to commodity derivative contracts were $3.7 million for the nine months ended September 30, 2013. Settlement receipts related to commodity derivative contracts were $1.9 million for the nine months ended September 30, 2012.

For the Remaining Properties, costs exceeded gross proceeds for the nine months ended September 30, 2013, therefore the Trust received approximately $1.5 million from the 7.5% Overriding Royalty attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt Properties.  The Trust received less than $0.1 million from the Remaining Properties during the first nine months of 2012.  The cumulative deficit of the net profits interest on the Remaining Properties, including the 7.5% Overriding Royalty, was approximately $3.9 million and $3.2 million, respectively, at September 30, 2013 and 2012.

PCEC charged the Trust $0.8 million and $0.3 million, respectively, for the Operating and Service Fee for the nine months ended September 30, 2013 and 2012. The annual amount of the Operating and Service Fee is $1.0 million.

The total cash received by the Trust from PCEC for the nine months ended September 30, 2013 was approximately $53.1 million compared to $24.2 million for the nine months ended September 30, 2012.  The Trustee paid general and administrative expenses of $0.6 million during the nine months ended September 30, 2013 compared with $0.5 million during the first nine months of 2012.  Expenses paid during the nine months ended September 30, 2013 consisted primarily of Trustee fees, accounting, tax and legal fees and New York Stock Exchange listing fees while the expenses paid during the first nine months of 2012 primarily consisted of Trustee fees, legal fees and New York Stock Exchange listing fees. Distributable income was approximately $52.5 million and $23.8 million, respectively, for the nine months ended September 30, 2013 and 2012.

Liquidity and Capital Resources

Other than Trust administrative expenses, including payment of the PCEC operating and services fee and 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, in excess of 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.

Each month, the Trustee pays Trust obligations and expenses and distributes 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

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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 ended September 30, 2013, there were no borrowings.

Distributions Paid and Declared After Quarter End

On October 14, 2013, the distribution of $0.15761 per Trust Unit, which was declared on September 24, 2013, was paid to Trust unitholders owning Trust units as of October 4, 2013.

On October 24, 2013 the Trust declared a distribution of $0.14756 per unit to unitholders of record as of November 7, 2013.  The distribution is payable to Trust unitholders on November 14, 2013.

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.

New Accounting Pronouncements

As the Trust’s financial statements are prepared using 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 read “Item 7. Trust’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” of the Trust’s 2012 Annual Report on Form 10-K for additional information regarding the Trust’s critical accounting policies and estimates. There were no material changes to the Trust’s critical accounting policies or estimates during the quarter ended September 30, 2013.

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 much 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 bankruptcy risk related to PCEC.  The bankruptcy of PCEC could impede the operation of wells and the development of proved undeveloped reserves that support the Trust’s Net Profits Interest and Overriding Royalty Interest.  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 commodity derivative contracts to reduce the exposure of 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 commodity derivative contracts involves the risk that the counterparty to the contracts will be unable to meet its obligations under the contracts. The commodity derivative contracts are with Wells Fargo Bank, National Association.  All payments from the commodity derivative 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,

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as amended (“Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.  Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by PCEC to The Bank of New York Mellon Trust Company, N.A., as Trustee of the Trust, and its employees who participate in the preparation of the Trust’s periodic reports as appropriate to allow timely decisions regarding required disclosure.  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 September 30, 2013, 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.

PART II—OTHER INFORMATION

Item 1A.     Risk Factors

Risk factors relating to the Trust are discussed in Item 1A of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2012.  No material change to such risk factors occurred during the three months ended September 30, 2013.

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

None.

Item 3.        Defaults Upon Senior Securities

Not applicable.

Item 4.        Mine Safety Disclosures

Not applicable.

Item 5.        Other Information

None.

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: November 7, 2013

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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