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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, 2016

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)

1-512-236-6555

(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 July 27, 2016, 38,583,158 Units of Beneficial Interest in Pacific Coast Oil Trust were outstanding.

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “report”) 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 report, 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 report, 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;

·                  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 report. 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 report or to reflect the occurrence of unanticipated events, unless required by law.

This report 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 Item 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.

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.

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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/or natural gas, such as the NYMEX crude oil price, and the wellhead price received.

Dry hole or well—A well found to be incapable of producing either oil and natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Economically producible—A resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Exploratory well—A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is not a development well.

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.

FASB—Financial Accounting Standards Board.

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

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.

NGLs— The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

Net profits interest (“NPI”)—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.

NYMEX—New York Mercantile Exchange.

Oil—Crude oil and condensate.

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.

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Overriding royalty interest —A fractional, undivided interest or right of participation in the oil or natural gas, or in the proceeds from the sale of oil and natural 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 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.

U.S. GAAP— Generally accepted accounting principles in the United States.

West Texas Intermediate (“WTI”)—Light, sweet crude oil with high API gravity and low sulfur content used as the benchmark for U.S. crude oil refining and trading. WTI is deliverable at Cushing, Oklahoma to fill NYMEX futures contracts for light, sweet crude oil.

Working interest—The right granted to the lessee of a property to explore for and to produce and own oil, natural 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, Liabilities 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 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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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 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 Annual 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 concurrently with the initial public offering of the Trust’s units of beneficial interest (“Trust 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 (the “Developed Properties”) and either a 25% 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 continues 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 (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, which PCEC estimates will occur in approximately 2026.  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 or PCEC 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. See “Note 6. Funding Commitment and Letter of Credit” for information regarding borrowings by the Trust from PCEC in 2016.

The Trust is not subject to any pre-set termination provisions based on 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 Conveyed Interests, (2) the annual cash proceeds received by the Trust attributable to the Conveyed Interests, in the aggregate, is less than $2.0 million for each of any two consecutive years, (3) the holders of at least 75% of the outstanding Trust Units vote in favor of dissolution or (4) the Trust is judicially dissolved.

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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 Overriding Royalty Interest, which are collectively referred to as the Conveyed Interests.

Concurrent with the Conveyance, PCEC sold 18,500,000 units of beneficial interest in the Trust (“Trust Units”) to the public in an initial public offering.  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, PCEC and other persons or entities (the “Other Selling Unitholders”) sold 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). On September 23, 2013, PCEC distributed 11,216,661 Trust Units to the Other Selling Unitholders.  Immediately following the distribution, the Other Selling Unitholders sold 8,500,000 Trust Units, and PCEC sold an additional 5,000,000 Trust Units, for a total sale of 13,500,000 Trust Units. PCEC retained 3,866,497 Trust Units, or 10% of the issued and outstanding Trust Units.  The Trust received no proceeds from either sale of these Trust Units.

On June 9, 2014, PCEC distributed 3,866,497 Trust Units, or the remaining 10% of the issued and outstanding Trust Units it owned to PCEC’s management and owners. Certain holders of the Trust Units affiliated with PCEC sold an aggregate of 2,654,436 Trust Units pursuant to an underwritten secondary public offering at a price of $13.00 per Trust Unit ($12.70 per Trust Unit, net of underwriting discounts and commissions). None of the Trust, PCEC or PCEC’s management sold any Trust Units in the secondary offering nor received any proceeds from the offering. The Trust Units were sold pursuant to a prospectus supplement and an accompanying prospectus as part of an effective shelf registration statement filed by the Trust with the Securities and Exchange Commission (the “SEC”).

Note 2.   Trust Significant Accounting Policies

Basis of Accounting

The accompanying Statement of Assets and Trust Corpus as of December 31, 2015, which has been derived from audited financial statements, and the unaudited interim financial statements as of June 30, 2016 and for the three months and six months ended June 30, 2016 and 2015 have been prepared pursuant to the rules and regulations of the SEC. 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 Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (“2015 Annual Report”).

In the opinion of the Trustee, the accompanying unaudited financial statements reflect all adjustments that are necessary for a fair statement 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;

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·  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 contingent liabilities under U.S. 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 balance. The production and net reserves used in the amortization calculation are determined using the economic interest method, where the sum of the net profits payments are divided by the effective price per barrel of oil equivalent resulting in the volume of production and reserves used in the calculation. For the three months ended June 30, 2016 and 2015, amortization expense was $109,053 and $1.4 million, respectively.  For the six months ended June 30, 2016 and 2015, amortization expense was $773,632 and $3.1 million, respectively. Such amortization does not affect cash earnings of the Trust.  Accumulated amortization as of June 30, 2016 and December 31, 2015 was $56.2 million and $55.5 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 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. There was no impairment as of June 30, 2016 or December 31, 2015.

While these statements differ from financial statements prepared in accordance with U.S. 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 SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Note 3.   Income Taxes

Federal 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 therefore is not 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 or her pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his or her 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 (and includes 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 will provide 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 tax circumstances. Unitholders should consult their tax advisors about the federal tax consequences relating to owning the Trust Units.

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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 is not 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.

Note 4.   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 from that month (such as interest earned on any amounts reserved by the Trustee), 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 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. Due to the decline in commodity prices, the Trust has not made distributions since January 2016. The following table illustrates information regarding the Trust’s distributions paid during the six months ended June 30, 2016 and 2015.

Six Months Ended June 30, 2016

Six Months Ended June 30, 2015

Note 5.   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 each of the three-month and six-month periods ended June 30, 2016, the Trust paid $50,000 and $100,000, respectively, to the Trustee. During each of the three-month and six-month periods ended June 30, 2016, the Trust paid $2,000 to the Delaware Trustee. During each of the three-month and six-month periods ended June 30, 2015, the Trust paid $50,000 and $100,000, respectively, to the Trustee. During each of the three-month and six-month periods ended June 30, 2015, the Trust paid $2,000 to the Delaware Trustee.

PCEC Operating and Services Fee.  Under the terms of the Operating and Services Agreement by and between PCEC and the Trust (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 which is revised annually based on changes to the Consumer Price Index.  The monthly operating and services fee was $86,330 during the first quarter of 2015 and was $87,730 from April 1, 2015 through the end of the first quarter of 2016. On April 1, 2016, the monthly operating and services fee changed to $87,834. The 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, 2016 and 2015, PCEC charged the Trust $356,386 and $260,389,

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respectively, for the operating and services fee. During the six months ended June 30, 2016 and 2015, PCEC charged the Trust $526,485 and $519,378, respectively, for the operating and services fee. The Trust paid the operating and services fee in full for the month of January 2016. However, because the Trust did not have enough cash to pay the operating and services fee in full for the months of February 2016 and March 2016, the Trust made partial payments of  $55,977 for February and $26,392 for March. For the months of April, May, and June 2016, the Trust was not able to make payments of $87,730, $87,730, and $87,834, respectively, without executing a promissory note and borrowing funds from PCEC. All operating and services fees have now been completely paid through June 30, 2016 as a part of the borrowings under the PCEC Promissory Note.

Note 6.   Funding Commitment and Letter of Credit

On February 25, 2016, the Trust entered into a Promissory Note with PCEC (“Promissory Note”) and borrowed $232,000 to pay general and administrative expenses. Under the Promissory Note, the Trust agreed to pay interest on the principal amount of the outstanding note at a rate of 8.5% per annum from February 29, 2016 until maturity. The note will mature on March 31, 2018.  For the three months ended June 30, 2016, the Trust borrowed an additional $514,789 on the Promissory Note. As of June 30, 2016, the Trust had $746,789 of borrowings outstanding on the Promissory Note.  Interest expense on the outstanding borrowings will be recorded as it is paid to PCEC. For the three months and six months ending June 30, 2016, the Trust incurred a total of $9,222 in interest, which has been included in the borrowings under the Promissory Note. No further distributions will be made to Trust unitholders until the amounts borrowed, including interest thereon, are repaid.

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. 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. Since PCEC loaned funds to the Trust and if the Trust draws on the letter of credit, 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. PCEC has agreed to loan funds to the Trust necessary to pay such expenses through a written promissory note as stipulated by the Trust Agreement.

Note 7.   Commitments and Contingencies

Legal Proceedings. The Trust has been named as a defendant in a putative class action as described below.

On July 1, 2014, Thomas Welch, individually and on behalf of all others similarly situated, filed a putative class action complaint in the Superior Court of California, County of Los Angeles, against the Trust, PCEC, PCEC (GP) LLC, Pacific Coast Energy Holdings LLC, certain executive officers of PCEC (GP) LLC and others.

The complaint asserts federal securities law claims against the Trust and other defendants and states that the claims are made on behalf of a class of investors who purchased or otherwise acquired Trust securities pursuant or traceable to the registration statement that became effective on May 2, 2012 and the prospectuses issued thereto and the registration statement that became effective purportedly on September 19, 2013 and the prospectuses issued thereto. The complaint states that the plaintiff is pursuing negligence and strict liability claims under the Securities Act of 1933 and alleges that both such registration statements contained numerous untrue statements of material facts and omitted material facts. The plaintiff seeks class certification, unspecified compensatory damages, rescission on certain of plaintiff’s claims, pre-judgment and post-judgment interest, attorneys’ fees and costs and any other relief the Court may deem just and proper.

On October 16, 2014, Ralph Berliner, individually and on behalf of all others similarly situated, filed a second putative class action complaint in the Superior Court of California, County of Los Angeles, against the Trust, PCEC, PCEC (GP) LLC, Pacific Coast Energy Holdings LLC, certain executive officers of PCEC (GP) LLC and others. The Berliner complaint asserts the same claims and makes the same allegations, against the same defendants, as are made in the Welch complaint. In November 2014, the Welch and Berliner actions were consolidated into a single action.

On December 8, 2015, the parties agreed in principle to settle the consolidated action, and are currently seeking preliminary approval of the settlement by the court. The Trust believes that it is fully indemnified by PCEC against any liability or expense it might incur in connection with the consolidated action.

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Note 8.   Property Tax Settlement

On March 23, 2016, PCEC reached a settlement agreement with the Santa Barbara County Assessor’s Office on supplemental property tax bills related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental tax bills relate to the settlement of disputed property values for Orcutt and Orcutt Diatomite field locations for these periods. Amounts attributable to the periods from April 1, 2012 through June 30, 2016 total approximately $2.1 million for the Developed Properties and $1.3 million for the Remaining Properties and are chargeable in part to the Trust in the March 2016 production month calculation of the net profits. The property tax adjustment amounts attributable to the Trust increased the cumulative net profits deficits of the Developed Properties and the Remaining Properties by $1.4 million and $245,394, respectively, and will be subtracted from any future net profits until the cumulative net profits deficits have been reduced to zero.

Note 9.   Subsequent Events

On July 7, 2016, PCEC received a letter from the California Department of Conservation, Division of Oil, Gas & Geothermal Resources (“DOGGR”) revising regulations on injection operations, impacting West Pico’s three active water injection wells. Included in the revised regulation is a limit on the maximum injection pressures allowable to a level approximately 60% below current injection pressures. PCEC is currently not in compliance with the guidelines and is developing a work plan to address the new guidelines. If DOGGR does not grant PCEC sufficient time to address this problem it may be necessary to shut in approximately 300 barrels per day of production, which would have an adverse impact on Development Properties cash flow.  PCEC is exploring options to avoid a loss in production, however, it expects any such efforts to require capital expenditures and at least several months to complete.  In the absence of relief from such regulations, or a period of time in which to bring operations into compliance, PCEC will have an immediate need to shut in as noted above, or secure viable and legally compliant means of water disposal, which may render operations unprofitable or compliance impossible.

On July 13, 2016, the Trust borrowed an additional $128,966 from PCEC under the Promissory Note to cover operating and administrative expenses. The outstanding balance owed, including interest, under the Promissory Note was $875,755.

As previously disclosed in the Annual Report on Form 10-K of Pacific Coast Oil Trust filed on March 4, 2016, PCEC currently has permit applications pending to allow the drilling of an additional 96 steam injection wells on certain oil and natural gas properties located onshore in California in the Diatomite zone at Orcutt (the “Orcutt Hill Resource Enhancement Plan” or “OHREP”).  At a hearing on June 29, the Santa Barbara County Planning Commission (the “Commission”) instructed its staff to prepare Findings for Denial, which the Commission adopted by a 3-2 vote on July 13, 2016. On July 21, 2016, PCEC filed an appeal to the Santa Barbara County Board of Supervisors. Hearings on any appeal are expected to occur approximately two months after an appeal is filed. There can be no assurance that the Santa Barbara County Board of Supervisors will reverse the decision of the Commission and as a result there can potentially be a decrease in the future cash flows attributable to the Remaining Properties.

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 “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II, Item 7 of the Trust’s 2015 Annual Report.  The following review should also be read in conjunction with “Forward-Looking Statements” in this report and with “Part I — Item 1A — Risk Factors” in the Trust’s 2015 Annual Report.

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 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 natural 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.  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”).

Concurrently with the Trust’s initial public offering in May 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 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

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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, if any, the Trust is entitled to receive the Royalty Interest Proceeds, if any, and the Trust will 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 a “NPI Payout”).  Due to significant planned 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, which PCEC estimates will occur in approximately 2026.  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 is exposed to fluctuation in energy prices in the normal course of business due to the Net Profits Interest in the Underlying Properties. The revenues derived from the Underlying Properties depend substantially on prevailing crude oil prices and, to a lesser extent, natural gas prices. As a result, commodity prices affect the amount of cash flow available for distribution to the Trust unitholders. For example, since February 2016, because of a decline in average realized prices, no cash distributions have been made as Trust expenses exceeded the proceeds received from the Conveyed Interests. Lower prices may also reduce the amount of oil and natural gas that PCEC and its third party operators can economically produce.  In addition, no further distribution will be made to Trust unitholders until amounts borrowed by the Trust under the Promissory Note, including interest thereon, have been repaid in full and the cumulative deficit for the Developed Properties has been reduced to zero.

Once distributions return, 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 Trust Units as of the applicable record date (generally within five business days after 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 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 continue to decline over time.

Commodity Prices

In the second quarter of 2016, the WTI crude oil spot price averaged approximately $45.46 per Bbl, compared to approximately $57.85 per Bbl in the second quarter of 2015. The WTI crude oil spot price decreased from a high of $61.36 per Bbl in June 2015 to a low of $26.19 per Bbl in February 2016. Lower crude oil prices may not only decrease the Trust’s distributable income, but may also reduce the amount of crude oil that PCEC can produce economically and therefore potentially lower the Trust’s crude oil reserves.  In the second quarter of 2016, approximately 98% of production from the Developed Properties consisted of oil and 100% of production from the Remaining Properties consisted of oil.

Prices for natural gas in many markets are aligned both with supply and demand conditions in their respective regional markets and with the overall U.S. market. Natural gas prices are also typically higher during the winter period when demand for heating is greatest in the U.S.  In the second quarter of 2016, the Henry Hub price averaged approximately $2.15 per MMBtu, compared with approximately $2.75 per MMBtu in the second quarter of 2015. The Henry Hub spot price decreased from a high of $3.32 per MMBtu in January 2015 to a low of $1.49 per MMBtu in March 2016.

A decline or increase in oil and natural gas prices increases the uncertainty as to the impact of commodity prices on our estimated proved reserves. We are unable to predict future commodity prices with any greater precision than the futures market.  A prolonged period of depressed commodity prices could have a significant impact on the volumetric quantities of PCEC’s proved reserve portfolio.

2016 Capital Program Summary

PCEC informed the Trustee at the beginning of 2016 that its 2016 capital program is expected to total approximately $3.4 million focused on mandatory facility upgrades at Orcutt Field and Orcutt Diatomite, rate-generating projects, and Orcutt Diatomite permitting fees.  This total includes expected investments of approximately $2.0 million ($1.6 million net to the Trust’s interest) in the

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Developed Properties and approximately $1.4 million expected to be spent on the Remaining Properties ($350,000 net to the Trust’s interest).

Properties

The Underlying Properties consist of the Developed Properties and 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, 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 been used to repay 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 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 Conveyed Interests, (2) the annual cash proceeds received by the Trust attributable to the Conveyed Interests, in the aggregate, are 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. As of July 28, 2016, $228,863 has been made available for distribution to the Trust in 2016.  For additional information, see “Part II - Item 1A. - Risk Factors-Distributable Cash to the Trust.”

On April 6, 2015, PCEC received a letter from DOGGR mandating the suspension of cyclic steaming operations in PODS 2 and 4 at Orcutt Diatomite, citing concern over surface expressions related to two wells occurring late in 2014 and the potential for landslides on the property.  This resulted in the suspension of steaming to 22 wells and curtailed production by approximately 300 barrels of oil per day. PCEC undertook significant testing and has installed monitoring equipment pursuant to direction from DOGGR. PCEC continues to cooperate with DOGGR to develop and implement a work plan that addresses DOGGR’s concerns. This resulted in a letter from DOGGR, received April 25, 2016, giving approval to recommence steaming at PODS 2 and 4, conditional upon further well testing. PCEC has carried out the required well testing on POD 4 and recommenced steaming on 11 POD 4 wells in May 2016.

During 2015, DOGGR discussed with PCEC the modification of existing well permits for approximately 25 water injection wells located at the Orcutt Field, which could require certain changes to operating procedures or well modifications. In a letter dated September 30, 2015, PCEC proposed and has implemented a schedule to modify one of the affected injection wells each quarter until all have been modified. The first three such modifications were successfully completed in the first half of 2016 and PCEC’s capital budget for 2016 includes one additional modification during the second half of 2016. If DOGGR were to order the modifications to be

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carried out more rapidly, PCEC’s capital costs could significantly increase. Alternatively, PCEC could choose or be required to shut in all or a portion of the affected injection wells, which would result in a loss of production.

On July 7, 2016, PCEC received a letter from DOGGR revising regulations on injection operations, impacting West Pico’s three active water injection wells. Included in the revised regulation is a limit on the maximum injection pressures allowable to a level approximately 60% below current injection pressures. PCEC is currently not in compliance with the guidelines and is developing a work plan to address the new guidelines. If DOGGR does not grant PCEC sufficient time to address this problem it may be necessary to shut in approximately 300 barrels per day of production, which would have an adverse impact on Development Properties cash flow.  PCEC is exploring options to avoid a loss in production, however, it expects any such efforts to require capital expenditures and at least several months to complete.  In the absence of relief from such regulations, or a period of time in which to bring operations into compliance, PCEC will have an immediate need to shut in as noted above, or secure viable and legally compliant means of water disposal, which may render operations unprofitable or compliance impossible.

Property Taxes

On March 23, 2016, PCEC reached a settlement agreement with the Santa Barbara County Assessor’s Office on supplemental property tax bills related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental tax bills relate to the settlement of disputed property values for Orcutt and Orcutt Diatomite field locations for these periods. Amounts attributable to the periods from April 1, 2012 through June 30, 2016 total approximately $2.1 million for the Developed Properties and $1.3 million for the Remaining Properties and are chargeable in part to the Trust in the March 2016 production month calculation of the net profits. The property tax adjustment amounts attributable to the Trust will increase the cumulative net profits deficits of the Developed Properties and the Remaining properties by $1.4 million and $245,394, respectively, and will be subtracted from any future net profits until the cumulative net profits deficits have been reduced to zero.

Results of Operations for the Three Months Ended June 30, 2016 and 2015

For the three months ended June 30, 2016, income from Conveyed Interests received by the Trust amounted to $43,819 compared with $2.0 million for the three months ended June 30, 2015.  The net profits calculated during the three months ended June 30, 2016 was associated with net profits for oil and natural gas production from the Developed Properties during the months of February, March, and April 2016, and 7.5% overriding royalty interest for oil production from the Remaining Properties located in PCEC’s Orcutt Field and Orcutt Diatomite properties during the months of February, March, and April 2016. However, there were no net profits received by the Trust for oil and natural gas production from the Developed Properties during the month of February, March, and April 2016 as operating expenses and capital expenditures exceeded revenues. The net profits received by the Trust during the three months ended June 30, 2015 was associated with net profits for oil and natural gas production during the months of February, March, and April 2015.

Oil and natural gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and natural gas prices and the total amount of production expense and development costs.  As oil and natural gas prices change, the Trust’s share of the production volumes is impacted as the quantity of production to cover expenses and development costs in reaching the net profits break-even level changes inversely with price.  Accordingly, the Underlying Property production volumes do not correlate with the Trust’s net profit share of those volumes in any given period.  Therefore, the comparative discussion of oil and natural gas volumes is based on the Underlying Properties as stated in the table below.

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 during the three months ended June 30, 2016 and 2015.

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(a)  Crude oil sales represented 98% and 96% of sales volumes from the Developed Properties for the three months ended June 30, 2016 and 2015, respectively.

(b) Production costs include lease operating expenses and production and other taxes.

(c)  Crude oil sales represented 100% and 100% of total sales volumes from the Remaining Properties for the three months ended June 30, 2016 and 2015, respectively.

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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 three months ended June 30, 2016 and 2015 was determined as shown in the following table:

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(1) Increase in Production and other taxes:

During the three months ended June 30, 2016, production and other taxes included $2,094,914 for the Developed Properties and $1,327,040 for the Remaining Properties related to the settlement of disputed property values attributable to the Trust for the periods April 1, 2012 through June 30, 2016.

(1) Production and other taxes in the second quarter of 2016 include supplemental property tax bills from the Santa Barbara County Assessor’s Office related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental property tax bills total approximately $2.1 million for the Developed Properties and $1.3 million for the Remaining Properties.

(2) Income from 80% Net Profits Interest in the second quarter of 2016 represents three months of net losses from the Conveyed Interests during the production months of February, March, and April 2016 as discussed in footnote 2.

(3) Property tax adjustment amounts related to PCEC not applicable to the Trust based on partial ownership of the Trust by PCEC from May 8, 2012 through June 9, 2014.

(4) There were no net profits for the second quarter of 2016 as operating expenses and capital expenditures exceeded revenues. The excess of operating expenses and capital expenditures over revenues added to the cumulative deficit balance.

(5) Property tax adjustment amounts related to PCEC not applicable to the Trust based on partial ownership of the Trust by PCEC from May 8, 2012 through June 9, 2014.

Three Months Ended June 30, 2016 and 2015

Developed Properties — For the three months ended June 30, 2016, direct operating expenses and development expenses from the Developed Properties exceeded revenues by $1.8 million. For the three months ended June 30, 2015, excess revenues over direct operating expenses and development expenses was $2.5 million.  The decrease is primarily attributable principally to lower oil prices and lower production in the three months ended June 30, 2016 compared to the three months ended June 30, 2015. Average realized prices decreased by $13.94 per Bbl, or 32%, and sales volumes decreased 45 MBoe, or 16%. Orcutt, Orcutt Diatomite, and West Pico all had decreased volumes for the three months ended June 30, 2016 versus the three months ended June 30, 2015. Total lease operating expenses included in the net profits calculation during the quarter were $5.3 million for the three months ended June 30, 2016 compared to $7.6 million for the three months ended June 30, 2015. The decrease is primarily attributable to lower operating

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expenses and workover expenditures at Orcutt Field, Orcutt Diatomite, Sawtelle and West Pico, which resulted from lower fuel and utilities, chemicals, company labor, and workover expenditures. Total capital expenditures were approximately $0.8 million for the three months ended June 30, 2016 compared to $1.0 million for the three months ended June 30, 2015.  The decrease is primarily due to decreased well work at West Pico, Orcutt Field, Orcutt Diatomite and Sawtelle. Production and other taxes were approximately $2.5 million for the three months ended June 30, 2016 compared to $0.9 million for the three months ended June 30, 2015 primarily due to the County of Santa Barbara property tax settlement reached in March 2016. Income from 80% Net Profits Interest for the three months ended June 30, 2016 was $0, which resulted in no net profits in April, May, or June 2016 as operating expenses and capital expenditures exceeded revenues, compared to $2.0 million of income for the three months ended June 30, 2015.  Since a deficit existed as a result of the net profits interest on the Developed Properties from the Conveyed Interests during the production months of January through April, the Trust will not receive any net profits until the cumulative net profits deficit is recovered in full.  The cumulative deficit of the net profits interest on the Developed Properties was $1.7 million at June 30, 2016.

Remaining Properties — Direct operating expenses and development expenses from the Remaining Properties exceeded revenues by $1.6 million for the three months ended June 30, 2016 compared to direct operating expenses and development expenses exceeding revenues from the Remaining Properties of $42,321 for the three months ended June 30, 2015. Average realized prices decreased by $18.06 per Bbl, or 41%, and sales volumes decreased 19 MBoe, or 23%, both contributing to a decrease in 2016 distributable income compared to 2015. Orcutt and Orcutt Diatomite had decreased volumes for the three months ended June 30, 2016 versus the three months ended June 30, 2015. Capital expenditures were $295,044 for the three months ended June 30, 2016 compared to $2.1 million for the three months ended June 30, 2015. The decrease in capital expenditures was primarily due to lower expenditures for the Remaining Properties in the Orcutt Field and Orcutt Diatomite properties. Since a cumulative deficit existed on the 25% net profits interest, the Trust received approximately $43,819 and $248,206 during the three months ended June 30, 2016 and 2015, respectively, from the 7.5% overriding royalty attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt Field and Orcutt Diatomite properties.  The cumulative deficit of the net profits interest on the Remaining Properties, including payments to the Trust pursuant to the 7.5% overriding royalty, was approximately $2.2 million at June 30, 2016 compared to $1.9 million at June 30, 2015.

PCEC Operating & Services Fee — PCEC charged the Trust approximately $263,294 for operating and services fees for the three months ended June 30, 2016 compared to $260,389 for the three months ended June 30, 2015. The Trust owed PCEC $93,091 for outstanding Operating and Services Fees that were not paid as of March 31, 2016. The Trust borrowed funds from PCEC under the Promissory Note to fund payments of the $93,091 and the $263,294 for a total amount paid in the three months ended June 30, 2016 of $356,386.

Trust Administrative Expenses — The Trustee paid general and administrative expenses of $193,000 for the three months ended June 30, 2016 compared to $250,000 for the three months ended June 30, 2015.  The decrease in general and administrative expenses for the three months ended June 30, 2016, was primarily due to the timing of payments related to auditing fees and NYSE listing fee, which were paid during the three months ended March 31, 2016 compared to the prior year payments of these items in the three months ended June 30, 2015. Since the Trust did not have enough cash to pay its expenses, it borrowed $514,789 from PCEC from April to June 2016 (see “Liquidity and Capital Resources” below).

Distributable Income — The total cash received by the Trust from PCEC for the three months ended June 30, 2016 was $0. There was no cash transferred to the Trustee from distributable income for the months of April, May, and June 2016 as the PCEC operating and service fee combined with the settlement of the supplemental property tax bills exceeded income from the Conveyed Interests. The total cash received by the Trust from PCEC for the three months ended June 30, 2015 was approximately $2.0 million, which represents the cash received for the months of February, March and April 2015, as income from the Conveyed Interests exceeded administrative expenses. Distributable income was $1.7 million for the three months ended June 30, 2015.

Results of Operations for the Six Months Ended June 30, 2016 and 2015

For the six months ended June 30, 2016, income from Conveyed Interests received by the Trust amounted to $477,781 compared with $6.2 million for the six months ended June 30, 2015.  The net profits received by the Trust during the six months ended June 30, 2016 was associated with net profits for oil and natural gas production from the Developed Properties during the months of November and December 2015, and 7.5% overriding royalty interest for oil production from the Remaining Properties located in PCEC’s Orcutt Field and Orcutt Diatomite properties during the months of November and December 2015 and January, February, March, and April 2016. However, there were no net profits for oil and natural gas production from the Developed Properties during the months of January, February, March, and April 2016 as operating expenses and capital expenditures exceeded revenues. The net profits received by the Trust during the six months ended June 30, 2015 was associated with net profits for oil and natural gas production during the months of November and December 2014 and January, February, March, and April 2015.

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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 during the six months ended June 30, 2016 and 2015.

(a)  Crude oil sales represented 96% and 98% of sales volumes from the Developed Properties for the six months ended June 30, 2016 and 2015, respectively.

(b) Production costs include lease operating expenses and production and other taxes.

(c)  Crude oil sales represented 100% of total sales volumes from the Remaining Properties for the six months ended June 30, 2016 and 2015, respectively.

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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 six months ended June 30, 2016 and 2015 was determined as shown in the following table:

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(1) Increase in Production and other taxes:

During the six months ended June 30, 2016, production and other taxes included $2,094,914 for the Developed Properties and $1,327,040 for the Remaining Properties related to the settlement of disputed property values attributable to the Trust for the periods April 1, 2012 through June 30, 2016.

(1) Production and other taxes in the second quarter of 2016 include supplemental property tax bills from the Santa Barbara County Assessor’s Office related to the tax years covering the periods July 1, 2011 through June 30, 2016. The supplemental property tax bills total approximately $2.1 million for the Developed Properties and $1.3 million for the Remaining Properties.

(2) Income from 80% Net Profit Interests from the Conveyed Interests during the production months of February 2016 through April 2016 resulted in a deficit as operating expenses and capital expenditures exceeded revenues. As a result, the Trust will not receive any net profits until the cumulative net profits deficit is recovered in full.

(3) Property tax adjustment amounts related to PCEC not applicable to the Trust based on partial ownership of the Trust by PCEC from May 8, 2012 through June 9, 2014

(4) There were no net profits for the first six months of 2016 as operating expenses and capital expenditures exceeded revenues. The excess of operating expenses and capital expenditures over revenues added to the cumulative deficit balance.

Six Months Ended June 30, 2016 and 2015

Developed Properties — For the six months ended June 30, 2016, direct operating expenses and development expenses from the Developed Properties exceeded revenues by $2.1 million, which consisted of a loss from the Developed Properties of $2.5 million for the months of March, April, May, and June 2016 and income from the Developed Properties of $0.4 million for the months of January and February 2016. For the six months ended June 30, 2015, excess revenues over direct expenses and development expenses was $7.2 million.  The decrease in income for the six months ended June 30, 2016 is attributable principally to lower oil prices and lower production compared to the six months ended June 30, 2015. Average realized prices decreased by $18.51 per Bbl, or 39%, and sales volumes decreased 75 MBoe, or 13% primarily attributable to lower volumes from our Orcutt Field, Orcutt Diatomite, and West Pico properties. Total lease operating expenses included in the net profits calculation were $12.4 million for the six months ended June 30, 2016 compared to $16.2 million for the six months ended June 30, 2015. The decrease is primarily attributable to lower operating

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expenses and workover expenditures at Orcutt Field, Orcutt Diatomite, Sawtelle and West Pico, which resulted from lower commodity prices. Total capital expenditures were approximately $0.9 million for the six months ended June 30, 2016 compared to $2.2 million for the six months ended June 30, 2015.  The decrease is primarily due to lower well work at West Pico, Orcutt Field, Orcutt Diatomite and Sawtelle. Production and other taxes were approximately $3.3 million for the six months ended June 30, 2016 compared to $1.9 million for the six months ended June 30, 2015. The increase in production and other taxes is primarily due to the County of Santa Barbara property tax settlement reached in March 2016. (see Footnote 6). Loss from 80% Net Profits Interest for the six months ended June 30, 2016 was $1.7 million as operating expenses and capital expenditures exceeded revenues compared to $5.7 million of income for the six months ended June 30, 2015.  Since a deficit existed as a result of the net profits interest on the Developed Properties, the Trust will not receive any net profits until the cumulative net profits deficit is recovered in full.  The cumulative deficit of the net profits interest on the Developed Properties was $1.7 million at June 30, 2016.

Remaining Properties — Direct operating expenses and development expenses from the Remaining Properties exceeded revenues by $1.9 million for the six months ended June 30, 2016 compared to excess revenues over direct operating expenses and development expenses from the Remaining Properties of approximately $1.0 million for the six months ended June 30, 2015. Average realized prices decreased by $21.04 per Bbl, or 45%, and sales volumes decreased 25 MBoe, or 16%, both contributing to a decrease in 2016 distributable income compared to 2015. Orcutt and Orcutt Diatomite had decreased volumes for the six months ended June 30, 2016 versus the six months ended June 30, 2015. Capital expenditures were $0.8 million for the six months ended June 30, 2016 compared to $3.0 million for the six months ended June 30, 2015. The decrease in capital expenditures was primarily due to lower expenditures for the Remaining Properties in the Orcutt Field and Orcutt Diatomite properties. Since a cumulative deficit existed on the 25% net profits interest, the Trust received approximately $140,357 and $493,724 during the six months ended June 30, 2016 and 2015, respectively, from the 7.5% overriding royalty attributable to the sale of all production from the Remaining Properties located on PCEC’s Orcutt Field and Orcutt Diatomite properties.  The cumulative deficit of the net profits interest on the Remaining Properties, including payments to the Trust pursuant to the 7.5% overriding royalty, was approximately $2.2 million at June 30, 2016 compared to $1.9 million at June 30, 2015.

PCEC Operating & Services Fee — PCEC charged the Trust approximately $526,485 for operating and services fees for the six months ended June 30, 2016 compared to $519,378 for the six months ended June 30, 2015. The Trust did not have enough cash to pay the operating and services fee in full for the six months ended June 30, 2016 and entered into the Promissory Note with PCEC. The trust borrowed funds under the Promissory Note to pay all Operating & Services fees due during the six months ended June 30, 2016.

Trust Administrative Expenses — The Trustee paid general and administrative expenses of $460,000 for the six months ended June 30, 2016 compared to $455,000 for the six months ended June 30, 2015. Since the Trust did not have enough cash to pay its expenses, it borrowed $746,789 from PCEC in the six months ended June 30, 2016 (see “Liquidity and Capital Resources” below).

Distributable Income — The total cash received by the Trust from PCEC for the six months ended June 30, 2016 was $263,863, which represents the cash received for the month of January 2016. The Trust general and administrative expenses and cash withheld for expenses were $35,000 for the month of January 2016, primarily consisting of Trustee fees and legal fees, and the distributable income remaining was $228,863 for the six months ended June 30, 2016.  There was no cash transferred to the Trustee from distributable income for the months of February, March, April, May, and June 2016 as the PCEC operating and service fee exceeded income from the Conveyed Interests. The total cash received by the Trust from PCEC for the six months ended June 30, 2015 was approximately $5.7 million, which represents the cash received for the months of January through June 2015, as income from the Conveyed Interests exceeded administrative expenses. The Trustee paid general and administrative expenses of $455,000 for the six months ended June 30, 2015, primarily consisting of Trustee fees, accounting fees and legal fees. Distributable income was $5.3 million for the six months ended June 30, 2015.

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, 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, as it has done as described below, the Trust unitholders will not receive distributions until the borrowed funds, including interest thereon, are repaid.

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Each month, the Trustee pays Trust obligations and expenses and distributes to the Trust unitholders the remaining proceeds, if any. 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 non-interest-bearing account.

Since Trust administrative expenses have now exceeded available cash, PCEC has agreed to loan funds to the Trust necessary to pay such expenses without requiring the Trust to draw under the letter of credit. On February 25, 2016, the Trustee entered into a Promissory Note with PCEC and borrowed $232,000 from PCEC. On April 14, 2016, the Trustee borrowed an additional $349,700 from PCEC under the terms of the Promissory Note entered into in February 2016. On May 18, 2016, the Trustee borrowed an additional $90,758 from PCEC under the terms of the Promissory Note entered into in February 2016. On June 10, 2016, the Trustee borrowed an additional $74,331 from PCEC under the terms of the Promissory Note entered into in February 2016. On July 13, 2016, the Trustee borrowed an additional $128,966 from PCEC under the terms of the Promissory Note entered into in February 2016. The total amount borrowed by the Trustee from PCEC under the terms of the Promissory Note entered into in February 2016 totaled $875,755 as of July 13, 2016.  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 additional funds to the Trust to pay necessary 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. No further distributions will be made to Trust unitholders until such amounts drawn or borrowed, including interest thereon, are repaid. The loan made by PCEC is on an unsecured basis, and the terms of the loan are substantially the same as those which would have been obtained in an arm’s-length transaction between PCEC and an unaffiliated third party.

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 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 read “Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” of the Trust’s 2015 Annual Report 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 June 30, 2016.

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 were to hold 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.

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.  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,

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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 report, the Trustee carried out an evaluation of the Trustee’s disclosure controls and procedures. Sarah Newell, 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, 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 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 commodity derivative contracts between PCEC and Wells Fargo Bank, National Association for the periods during which those contracts were in effect, and (B) conclusions and reports regarding reserves by the Trust’s independent reserve engineers.

During the quarter ended June 30, 2016, 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 1.                      Legal Proceedings

The Trust has been named as a defendant in a putative class action as described below.

On July 1, 2014, Thomas Welch, individually and on behalf of all others similarly situated, filed a putative class action complaint in the Superior Court of California, County of Los Angeles, against the Trust, PCEC, PCEC (GP) LLC, Pacific Coast Energy Holdings LLC, certain executive officers of PCEC (GP) LLC and others.

The complaint asserts federal securities law claims against the Trust and other defendants and states that the claims are made on behalf of a class of investors who purchased or otherwise acquired Trust securities pursuant or traceable to the registration statement that became effective on May 2, 2012 and the prospectuses issued thereto and the registration statement that became effective purportedly on September 19, 2013 and the prospectuses issued thereto. The complaint states that the plaintiff is pursuing negligence and strict liability claims under the Securities Act of 1933 and alleges that both such registration statements contained numerous untrue statements of material facts and omitted material facts. The plaintiff seeks class certification, unspecified compensatory damages, rescission on certain of plaintiff’s claims, pre-judgment and post-judgment interest, attorneys’ fees and costs and any other relief the Court may deem just and proper.

On October 16, 2014, Ralph Berliner, individually and on behalf of all others similarly situated, filed a second putative class action complaint in the Superior Court of California, County of Los Angeles, against the Trust, PCEC, PCEC (GP) LLC, Pacific Coast Energy Holdings LLC, certain executive officers of PCEC (GP) LLC and others. The Berliner complaint asserts the same claims and makes the same allegations, against the same defendants, as are made in the Welch complaint. In November 2014, the Welch and Berliner actions were consolidated into a single action.

On December 8, 2015, the parties agreed in principle to settle the consolidated action, and are currently seeking preliminary approval of the settlement by the court. The Trust believes that it is fully indemnified by PCEC against any liability or expense it might incur in connection with the consolidated action.

Item 1A.             Risk Factors.

There have been no material changes to the Risk Factors disclosed in “Part I - Item 1A. - Risk Factors” of our 2015 Annual Report and “Part II — Item 1A” of our 1st quarterly report on Form 10-A.

Distributable Cash to the Trust

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 annual cash proceeds received by the Trust attributable to the Conveyed Interests, in the aggregate, are 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 annual cash proceeds received by the Trust attributable to the conveyed Interests, in the aggregate, are less than $2.0 million for each of any two consecutive years. No cash has been available for distribution to the Trust for the months of February, March, April, May and June in 2016.  The net profits of any such sale will be distributed to the Trust unitholders. As a result, Trust unitholders may not recover their investment.

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: July 28, 2016

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

*              Asterisk indicates exhibit previously filed with SEC and incorporated herein by reference.

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