EX-99.1 7 d699006dex991.htm EX-99.1

Exhibit 99.1

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

APPRAISAL REPORT

as of OCTOBER 1,

2013 on

CERTAIN PROPERTIES

owned by

MAXUS ENERGY CORPORATION

EXECUTIVE SUMMARY

DEGOLYER AND MACNAUGHTON

TABLE of CONTENTS

|  | Page |
FOREWORD |  |  | 1 |
Scope of Investigation |  |  | 1 |
Authority |  |  | 2 |
Source of Information |  |  | 3 |
DEFINITION of RESERVES |  |  | 4 |
ESTIMATION of RESERVES |  |  | 8 |
VALUATION of RESERVES |  |  | l0 |
SUMMARY and CONCLUSIONS |  |  | 14 |

DEGOLYER AND MACNAUGHTON

5001 SPRING VALLEY ROAD

SUITE 800 EAST

DALLAS, TEXAS 75244

APPRAISAL REPORT

as of OCTOBER 1,

2013 on

CERTAIN PROPERTIES

owned by

MAXUS ENERGY CORPORATION

EXECUTIVE SUMMARY

FOREWORD

Scope of Investigation

This report is an appraisal, as of October 1, 2013, of the extent and value of the proved and probable crude oil, condensate, natural gas liquids (NGL), and natural gas reserves of certain properties that Maxus Energy Corporation (Maxus) has represented that it owns. The properties appraised consist of working and overriding royalty interests located in Oklahoma and Texas (Crescendo) and offshore Gulf of Mexico (Neptune).

Estimates of proved reserves presented in this report have been prepared in compliance with the regulations promulgated by the United States Securities and Exchange Commission (SEC). Estimates of probable reserves presented in this report have been prepared in accordance with the Petroleum Resources Management System (PRMS) approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. These reserves definitions are discussed in detail in the Definition of Reserves section of this report.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced after September 30, 2013. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by Maxus after deducting royalties and interests owned by others.

DEGOLYER AND MACNAUGHTON

This report also presents values for proved and probable reserves using initial prices and costs provided by Maxus. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). A detailed explanation of the future price and cost assumptions is included in the Valuation of Reserves section of this report.

Values shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, operating expenses, and capital costs from the future gross revenue. Operating expenses include field operating expenses, transportation expenses, compression charges, and an allocation of overhead that directly relates to production activities. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization. In this report, present worth values using a discount rate of 10 percent are reported in detail and values using discount rates of 5, 10, 15, 20, 25, and 30 percent are reported as totals.

Estimates of oil, condensate, NGL, and gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Authority

This report was prepared at the request of Mr. Fernando Segovia, Purchasing Manager, Maxus Energy Corporation.

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DEGOLYER AND MACNAUGHTON

Source of Information

Data used in the preparation of this report were obtained from Maxus, from reports filed with the appropriate regulatory agencies, and from other public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Maxus with respect to property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. It was not considered necessary to make a field examination of the physical condition and operation of the properties.

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DEGOLYER AND MACNAUGHTON

DEFINITION of RESERVES

Petroleum reserves included in this report are classified by degree of proof as proved or probable. Only proved and probable reserves have been evaluated for this report. Proved reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-lO(a) (1}-(32) of Regulation S-X of the SEC. Proved reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

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(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

The following definitions for developed and undeveloped reserves apply only to proved reserves evaluated herein.

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DEGOLYER AND MACNAUGHTON

Developed oil and gas reserves—Developed oil and gas reserves are reserves of any category 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 if the extraction is by means not involving a well.

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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4-10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

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DEGOLYER AND MACNAUGHTON

The probable reserves presented in this report have been prepared in accordance with the PRMS approved in March 2007 by the Society of Petroleum Engineers, the World Petroleum Council, the American Association of Petroleum Geologists, and the Society of Petroleum Evaluation Engineers. Probable and possible reserves are based on geoscience and/or engineering data similar to that used in estimates of proved reserves, but technical or other uncertainties preclude such reserves being classified as proved.

Probable Reserves—Probable reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50-percent probability that the actual quantities recovered will equal or exceed the 2P estimate.

Possible Reserves—Possible reserves are those additional reserves which analysis of geoscience and engineering data suggest are less likely to be recoverable than probable reserves. The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible reserves (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10-percent probability that the actual quantities recovered will equal or exceed the 3P estimate.

The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. Probable reserves in this report have not been adjusted in consideration of these additional risks to make them comparable to proved reserves. No possible reserves have been evaluated for this report.

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DEGOLYER AND MACNAUGHTON

ESTIMATION of RESERVES

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with practices generally recognized by the petroleum industry, which for proved reserves are as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” and for probable reserves are as presented in accordance with definitions established by the PRMS. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance and other engineering methods were used to estimate OOIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material-balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production based on current economic conditions.

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DEGOLYER AND MACNAUGHTON

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

Gas quantities estimated herein are expressed as wet gas and sales gas. Wet gas is defined as the total gas to be produced before reductions for volume loss due to fuel and flare consumption and reduction for plant processing. Sales gas is defined as that portion of the wet gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and plant processing. Gross gas quantities are reported as wet gas. Net gas quantities are reported as sales gas. All gas quantities are expressed at a temperature base of 60 degrees Fahrenheit COF) and at the legal pressure base of the state or area in which the reserves are located. Condensate reserves estimated herein are those to be recovered by normal lease separation.

In the preparation of this report, as of October 1, 2013, gross production estimated to October 1, 2013, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves. Production data from certain properties were available through April 2013. Data available from wells drilled to August 16, 2013, were used in this report.

The proved and probable reserves, as of October 1, 2013, of the properties appraised are estimated as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

|  | Gross Reserves |  |  | Net Reserves |
|  | Oil and Condensate (Mbbl) |  |  | NGL (Mbbl) |  |  | Wet Gas (MMcf) |  |  | Oil and Condensate (Mbbl) |  |  | NGL (Mbbl) |  |  | Sales Gas (MMcf) |
Proved |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Developed Producing |  |  | 8,056 |  |  |  | 187 |  |  |  | 463,860 |  |  |  | 753 |  |  |  | 25 |  |  |  | 2,897 |
Developed Nonproducing |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |
Undeveloped |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |
Total Proved |  |  | 8,056 |  |  |  | 187 |  |  |  | 463,860 |  |  |  | 753 |  |  |  | 25 |  |  |  | 2,897 |
Probable* |  |  | 5,699 |  |  |  | 192 |  |  |  | 4,460 |  |  |  | 748 |  |  |  | 25 |  |  |  | 392 |

* | Probable reserves have not been risk adjusted to make them comparable to proved reserves.

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DEGOLYER AND MACNAUGHTON

VALUATION of RESERVES

Revenue values in this report have been prepared using initial prices and costs specified by Maxus. Future prices were estimated using guidelines established by the SEC and the FASB.

In this report, values for proved and probable reserves are based on projections of estimated future production and revenue prepared for these properties with no risk adjustment applied to the probable reserves. Probable reserves involve substantially higher risk than proved reserves. Revenue values for probable reserves have not been adjusted to account for such risks; this adjustment would be necessary in order to make probable reserves values comparable with values for proved reserves.

The following assumptions were used for estimating future prices and costs:

Oil and Condensate Prices

Maxus has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Maxus requested that this report be delivered at the end of August 2013, approximately 30 days before the “as of’ date of this report. In doing so, the September 1, 2013, posted product price, the final product price used to determine the average product price for the 12-month period preceding the “as of’ date of the evaluation, was not available. At Maxus’ request the final product price used to calculate the average product price for the 12-month period preceding the “as of’ date of this report was the product price posted on August 16, 2013. Maxus supplied differentials by field to a West Texas Intermediate reference price of $95.10 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $92.96 per barrel of oil and condensate.

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DEGOLYER AND MACNAUGHTON

NGLPrices

Maxus supplied differentials by field to a reference price of $60.48 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $52.92 per barrel.

Natural Gas Prices

Maxus has represented that the natural gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Maxus requested that this report be delivered at the end of August 2013, approximately 30 days before the “as of’ date of this report. In doing so, the September 1, 2013, posted gas price, the final gas price used to determine the average gas price for the 12-month period preceding the “as of’ date of the evaluation, was not available. At Maxus’ request the final gas price used to calculate the average gas price for the 12-month period preceding the “as of’ date of this report was the gas price posted on August 16, 2013. The gas prices were calculated for each property using differentials to the Henry Hub reference price of $3.58 per million British thermal units (MMbtu) furnished by Maxus and held constant thereafter. The volume-weighted average price attributable to estimated proved reserves was $3.601 per thousand cubic feet.

Operating Expenses and Capital Costs

Estimates of operating expenses and capital costs based on current costs were used for the lives of the properties with no increases in the future based on inflation. In certain cases, future costs, either higher or lower than current costs, may have been used because of anticipated changes in operating conditions. Future capital costs were estimated using expected

2013 values and were not adjusted for inflation.

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DEGOLYER AND MACNAUGHTON

The estimated future revenue to be derived from the production and sale of the net proved and probable reserves, as of October 1, 2013, of the properties appraised is summarized as follows, expressed in thousands of dollars (M$):

|  | Developed Producing: |  |  | Developed Nonproducing: |  |  | Undeveloped |  |  | Total Proved |  |  | Probable* |
Future Gross Revenue, M$ |  |  | 81,757 |  |  |  | 0 |  |  |  | 0 |  |  |  | 81,757 |  |  |  | 72,291 |
Production and Ad Valorem Taxes, M$ |  |  | 908 |  |  |  | 0 |  |  |  | 0 |  |  |  | 908 |  |  |  | 0 |
Operating Expenses, M$ |  |  | 17,716 |  |  |  | 0 |  |  |  | 0 |  |  |  | 17,716 |  |  |  | 12,675 |
Capital Costs, M$ |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 13,500 |
Abandonment Costs, M$ |  |  | 28,800 |  |  |  | 0 |  |  |  | 0 |  |  |  | 28,800 |  |  |  | 0 |
Future Net Revenue**, M$ |  |  | 34,333 |  |  |  | 0 |  |  |  | 0 |  |  |  | 34,333 |  |  |  | 46,116 |
Present Worth at 10 Percent**, M$ |  |  | 30,218 |  |  |  | 0 |  |  |  | 0 |  |  |  | 30,218 |  |  |  | 29,764 |

* | Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.

** | Future income tax expenses were not taken into account in the preparation of these estimates.

The development of production and the resulting timing of capital expenditures were based on a development plan provided by Maxus.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235- 50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries - Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10(a) (1}-(32) of Regulation S-X and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8)(i), (ii), and (v}-(x) of Regulation S-K of the Securities and Exchange Commission; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein, (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year, and (iii) the as-of date of this report does not coincide with Maxus’ fiscal year.

This report was completed on August 30, 2013; therefore, events that may have occurred after the preparation of this report but before the “as-of’ date of October 1, 2013, that might have affected the reserves, prices, and costs used in the estimates presented herein were not taken into account.

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DEGOLYER AND MACNAUGHTON

To the extent that the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

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DEGOLYER AND MACNAUGHTON

SUMMARY and CONCLUSIONS

Maxus has represented that it owns interests in certain properties located in Oklahoma, Texas, and offshore Gulf of Mexico. The estimated net proved and probable reserves of the properties appraised, as of October 1, 2013, are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcD):

|  | Net Reserves |
|  | Oil and Condensate (Mbbl) |  |  | NGL (Mbbl) |  |  | Sales Gas (MMcf) |
Proved |  |  |  |  |  |  |  |  |  |  |  |
Developed Producing |  |  | 753 |  |  |  | 25 |  |  |  | 2,897 |
Developed Nonproducing |  |  | 0 |  |  |  | 0 |  |  |  | 0 |
Undeveloped |  |  | 0 |  |  |  | 0 |  |  |  | 0 |
Total Proved |  |  | 753 |  |  |  | 25 |  |  |  | 2,897 |
Probable* |  |  | 748 |  |  |  | 25 |  |  |  | 392 |

* | Probable reserves have not been risk adjusted to make them comparable to proved reserves.

Estimated revenue and costs attributable to Maxus’ interests in the reserves, as of October 1, 2013, of the properties appraised under the aforementioned assumptions concerning future prices and costs are summarized as follows, expressed in thousands of dollars (M$):

|  | Developed Producing |  |  | Developed Nonproducing |  |  | Undeveloped |  |  | Total Proved |  |  | Probable* |
Future Gross Revenue, M$ |  |  | 81,757 |  |  |  | 0 |  |  |  | 0 |  |  |  | 81,757 |  |  |  | 72,291 |
Production and Ad Valorem Taxes, M$ |  |  | 908 |  |  |  | 0 |  |  |  | 0 |  |  |  | 908 |  |  |  | 0 |
Operating Expenses, M$ |  |  | 17,716 |  |  |  | 0 |  |  |  | 0 |  |  |  | 17,716 |  |  |  | 12,675 |
Capital Costs, M$ |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 0 |  |  |  | 13,500 |
Abandonment Costs, M$ |  |  | 28,800 |  |  |  | 0 |  |  |  | 0 |  |  |  | 28,800 |  |  |  | 0 |
Future Net Revenue**, M$ |  |  | 34,333 |  |  |  | 0 |  |  |  | 0 |  |  |  | 34,333 |  |  |  | 46,116 |
Present Worth at 10 Percent**, M$ |  |  | 30,218 |  |  |  | 0 |  |  |  | 0 |  |  |  | 30,218 |  |  |  | 29,764 |

* | Values for probable reserves have not been risk adjusted to make them comparable to values for proved reserves.

** | Future income tax expenses were not taken into account in the preparation of these estimates.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the October 1, 2013, estimated oil and gas volumes. The reserves estimated in this report can be produced under current regulatory guidelines.

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DEGOLYER AND MACNAUGHTON

DeGolyer and MacNaughton IS an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Maxus. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Maxus. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716

SIGNED: August 30, 2013

|  | /s/ Paul J. Szatkowski. P.E.
|  | Paul J. Szatkowski. P.E.
|  | Senior Vice President
|  | DeGolyer and MacNaughton

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