Exhibit 99.1

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March 4,
2013

Mr. Mark L. Pease
BreitBurn Management Company, LLC
600 Travis Street, Suite 4800
Houston, Texas 77002

Mr. Michael J. Ulrich
The Bank of New York Mellon Trust Company, N.A.
    as Trustee of Pacific Coast Oil Trust
Global Corporate Trust
919 Congress, Suite 500
Austin, Texas 78701


Gentlemen:

In
accordance with your request, we have estimated the proved reserves and future revenue, as of December 31, 2012, to the Pacific Coast Oil Trust (PCOT) net profits and
overriding royalty interest in certain oil and gas properties located in California. We completed our evaluation on or about the date of this letter. It is our understanding that the proved reserves
estimated in this report constitute all of the proved reserves owned by PCOT. Our report dated January 30, 2013, sets forth our estimates of proved reserves and future revenue to the Pacific
Coast Energy Company LP (PCEC) interest in certain Orcutt properties located onshore in the Santa Maria Basin and certain East Coyote, Sawtelle, and West Pico properties located onshore in the
Los Angeles Basin; these properties are referred to herein as the "Underlying Properties". The estimates in this report have been prepared in accordance with the definitions and regulations of the
U.S. Securities and Exchange Commission (SEC) and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive
ActivitiesOil and Gas. Definitions are presented immediately following this letter. This report has been prepared for PCOT's use in filing with the SEC; in our opinion the assumptions,
data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The
Underlying Properties are categorized as "Developed Properties" or "Remaining Properties" based on their reserves category as of December 31, 2011. The net profits interests
entitle PCOT to receive 80 percent of the net profits from the sale of oil and natural gas production from Developed Properties and either 25 percent of the net profits from the sale of
oil and natural gas production from Remaining
Properties or a 7.5 percent overriding royalty interest in the Remaining Properties located in Orcutt Field for periods when net profits are not available.



GRAPHIC

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We
estimate the net reserves and future net revenue to the PCOT interest in these properties, as of December 31, 2012, to be:

Net Reserves

Future Net Revenue (M$)Property Group/Category

Oil
(MBBL)

NGL
(MBBL)

Gas
(MMCF)

Total

Present Worth
at 10%Developed PropertiesProved Developed Producing


7,350.1


5.3


1,500.8


761,758.6


395,933.0Proved Developed Non-Producing


965.0


0.0


34.9


95,412.8


48,673.6Total Developed Properties


8,315.1


5.3


1,535.7


857,171.4


444,606.6Remaining PropertiesProved Developed Producing


365.2


0.0


0.0


35,927.3


22,142.4Proved Developed Non-Producing


304.7


0.0


0.0


29,945.6


12,189.8Proved Undeveloped


1,579.2


22.2


45.0


157,633.5


59,603.7Total Remaining Properties


2,249.0


22.2


45.0


223,506.4


93,935.9All PropertiesProved Developed Producing


7,715.3


5.3


1,500.8


797,685.9


418,075.4Proved Developed Non-Producing


1,269.7


0.0


34.9


125,358.3


60,863.4Proved Undeveloped


1,579.2


22.2


45.0


157,633.5


59,603.7Total All Properties


10,564.1


27.5


1,580.7


1,080,677.8


538,542.5


Totals may not add because of rounding.


The
oil reserves shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United
States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

The
estimates shown in this report are for proved reserves. As requested, probable and possible reserves that exist for these properties have not been included. This report does not
include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated. Reserves categorization conveys the relative
degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk.

The
net reserves to the PCOT net profits interest are determined monthly using the economic interest method. By reserves category, the sum of the net profits payment and PCOT's share of
the production and ad valorem taxes is divided by the effective price per barrel of oil equivalent. The resulting net equivalent reserves are then allocated between oil, NGL, and gas in the same
proportion as the Underlying Properties.

Gross
revenue is PCOT's share of the gross (100 percent) revenue from the properties prior to any deductions. Future net revenue is after deductions for PCOT's share of production
taxes and ad valorem taxes but before consideration of any income taxes. The future net revenue has been discounted at an annual rate of 10 percent to determine its present worth, which is
shown to indicate the effect of time on the value of money. Future net revenue presented in this report, whether discounted or undiscounted, should not be construed as being the fair market value of
the properties.

Prices
used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for
each month in the period January through December 2012. For oil and NGL volumes, the average Wall Street Journal West Texas Intermediate (Cushing) cash/spot price of $94.71 per barrel is adjusted by
lease for quality, transportation fees, and regional price differentials.

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For
gas volumes, the average Henry Hub spot price of $2.757 per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant
throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $105.06 per barrel of oil, $96.13 per barrel of NGL,
and $2.868 per MCF of gas.

Because
PCOT owns no working interest in these properties, no operating costs or capital costs would be incurred. However, estimated operating costs and capital costs have been used to
confirm economic producibility and determine economic limits for the properties. Operating costs used in this report are based on operating expense records of BreitBurn Management Company, LLC
(BreitBurn). Operating costs are held constant throughout the lives of the properties, and capital costs are held constant to the date of expenditure. PCOT would not incur any costs due to
abandonment, nor would it realize any salvage value for the lease and well equipment.

For
the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. Since
PCOT owns a net profits and overriding royalty interest rather than a working interest in these properties, it would not incur any costs due to possible environmental liability.

We
have made no investigation of potential gas volume and value imbalances resulting from overdelivery or underdelivery to the PCOT interest. Therefore, our estimates of reserves and
future revenue do not include adjustments for the settlement of any such imbalances; our projections are based on PCOT receiving its net profits interest share of estimated future gross gas
production.

The
reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of
engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less
certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir
performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed
consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of
the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the
costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and
costs incurred by the working interest owners in recovering such reserves may vary from assumptions made while preparing this report.

For
the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, well test data, production data, historical price and cost
information, and property ownership interests. The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards
Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or
a combination of methods, including performance analysis, volumetric analysis, and analogy, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with
SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions
necessarily represent only informed professional judgment.

The
data used in our estimates were obtained from PCOT, PCEC, BreitBurn, public data sources, and the nonconfidential files of Netherland, Sewell & Associates, Inc. (NSAI)
and were accepted as

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accurate.
Supporting work data are on file in our office. The titles to the properties have not been examined by NSAI, nor has the actual degree or type of interest owned been independently confirmed.
The technical persons responsible for preparing the estimates presented herein meet the requirements
regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do
not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,NETHERLAND, SEWELL & ASSOCIATES, INC.Texas Registered Engineering Firm F-2699By:

/s/ C.H. (SCOTT) REES III, C.H. (Scott) Rees III, P.E. Chairman and Chief Executive OfficerBy:

/s/ J. CARTER HENSON, JR. J. Carter Henson, Jr., P.E. 73964 Senior Vice President

By:

/s/ MIKE K. NORTON Mike K. Norton, P.G. 441 Senior Vice PresidentDate Signed: March 4, 2013

Date Signed: March 4, 2013


JCH:LRG



Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our
clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and
conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital
document.


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DEFINITIONS OF OIL AND GAS RESERVESAdapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The
following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a). Also included is
supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932,
Extractive ActivitiesOil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1)Acquisition of properties.Costs incurred to purchase, lease or otherwise acquire a property, including
costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees,
legal costs, and other costs incurred in acquiring properties.

(2)Analogous reservoir.Analogous reservoirs, as used in resources assessments, have similar rock and fluid
properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide
concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following
characteristics with the reservoir of interest:



Instruction to paragraph (a)(2):    Reservoir properties must, in the aggregate, be no more favorable in the analog than in the
reservoir of
interest.

(3)Bitumen.Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or
semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its
natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4)Condensate.Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir
temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5)Deterministic estimate.The method of estimating reserves or resources is called deterministic when a single
value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6)Developed oil and gas reserves.Developed oil and gas reserves are reserves of any category that can be
expected to be recovered:



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Supplemental definitions from the 2007 Petroleum Resources Management System: Developed Producing ReservesDeveloped Producing Reserves are expected to be recovered from completion intervals that are open and producing at the
time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation. Developed Non-Producing ReservesDeveloped Non-Producing Reserves include shut-in and behind-pipe
Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing,
(2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves
are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated
or restored with relatively low expenditure compared to the cost of drilling a new well.


(7)Development costs.Costs incurred to obtain access to proved reserves and to provide facilities for
extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other
costs of development activities, are costs incurred to:



(8)Development project.A development project is the means by which petroleum resources are brought to the
status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several
fields and associated facilities with a common ownership may constitute a development project.

(9)Development well.A well drilled within the proved area of an oil or gas reservoir to the depth of a
stratigraphic horizon known to be productive.

(10)Economically producible.The term economically producible, as it relates to a resource, means a resource
which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil
and gas producing activities as defined in paragraph (a)(16) of this section.

(11)Estimated ultimate recovery (EUR).Estimated ultimate recovery is the sum of reserves remaining as of a
given date and cumulative production as of that date.

(12)Exploration costs.Costs incurred in identifying areas that may warrant examination and in examining
specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.
Exploration

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costs
may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which
include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:



(13)Exploratory well.An exploratory well is 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 any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14)Extension well.An extension well is a well drilled to extend the limits of a known reservoir.

(15)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. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or
laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms
"structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays,
areas-of-interest, etc.

(16)Oil and gas producing activities.



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Instruction 1 to paragraph (a)(16)(i):The oil and gas production function shall be regarded as ending at a "terminal point",
which is
the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function
as:



Instruction 2 to paragraph (a)(16)(i):For purposes of this paragraph (a)(16), the termsaleable
hydrocarbonsmeans hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.



(17)Possible reserves.Possible reserves are those additional reserves that are less certain to be recovered
than probable reserves.



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(18)Probable reserves.Probable reserves are those additional reserves that are less certain to be recovered
than proved reserves but which, together with proved reserves, are as likely as not to be recovered.



(19)Probabilistic estimate.The method of estimation of reserves or resources is called probabilistic when the
full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated
probabilities of occurrence.

(20)Production costs.



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(21)Proved area.The part of a property to which proved reserves have been specifically attributed.

(22)Proved oil and gas reserves.Proved oil and gas reserves are those quantities of oil and gas, which, by
analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically produciblefrom a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulationsprior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time.



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(23)Proved properties.Properties with proved reserves.

(24)Reasonable certainty.If deterministic methods are used, reasonable certainty means a high degree of
confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the
estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and
geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25)Reliable technology.Reliable technology is a grouping of one or more technologies (including computational
methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26)Reserves.Reserves are estimated remaining quantities of oil and gas and related substances anticipated to
be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will
exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to
implement the project.

Note to paragraph (a)(26):Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults
until those
reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive
reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from
undiscovered accumulations).

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Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive ActivitiesOil and Gas: 932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the
following shall be disclosed as of the end of the year: a.Proved oil and gas reserves (see paragraphs 932-235-50-3 through
50-11B)b.Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity
participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see
paragraph 932-235-50-7). The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting
purposes. 932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which
reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B: a.Future cash inflows.    These shall be computed by applying prices used in estimating the entity's proved oil and gas
reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at
year-end.b.Future development and production costs.    These costs shall be computed by estimating the expenditures to be incurred in
developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. if estimated development
expenditures are significant, they shall be presented separately from estimated production costs.c.Future income tax expenses.    These expenses shall be computed by applying the appropriate year-end statutory
tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties
involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas
reserves.d.Future net cash flows.    These amounts are the result of subtracting future development and production costs and future
income tax expenses from future cash inflows.e.Discount.    This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of
the future net cash flows relating to proved oil and gas reserves.f.Standardized measure of discounted future net cash flows.    This amount is the future net cash flows less the computed
discount.


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

(28)Resources.Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations.
A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

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(29)Service well.A well drilled or completed for the purpose of supporting production in an existing field.
Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for
in-situ combustion.

(30)Stratigraphic test well.A stratigraphic test well is a drilling effort, geologically directed, to obtain
information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests
identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development
type" if drilled in a known area.

(31)Undeveloped oil and gas reserves.Undeveloped oil and gas reserves are reserves of any category 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.



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From the SEC's Compliance and Disclosure Interpretations (October 26, 2009): Although several types of projectssuch as constructing offshore platforms and development in urban areas, remote locations or
environmentally sensitive locationsby their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into
consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the
rule. Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years
include, but are not limited to, the following: The company's level of ongoing significant development activities in the area to be developed (for
example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);The company's historical record at completing development of comparable long-term
projects;The amount of time in which the company has maintained the leases, or booked the reserves, without
significant development activities;The extent to which the company has followed a previously adopted development plan (for example,
if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be
appropriate); andThe extent to which delays in development are caused by external factors related to the physical
operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop
properties with higher priority).




(32)Unproved properties.Properties with no proved reserves.

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