Exhibit 99.1

January 26, 2018

Cabot Oil & Gas Corporation

Three Memorial City Plaza Building

840 Gessner Road, Suite 1400

Houston, Texas 77024-4152

Re:Audit of

Reserves and Future Net Revenues

As of December 31, 2017

SEC Price Case

Gentlemen:

At your request, Miller and Lents, Ltd. (M&L) performed an audit of the estimates of proved reserves of oil, and gas and the future net revenues associated with these reserves that Cabot Oil & Gas Corporation (Cabot) attributes to its net interests in oil and gas properties as of December 31, 2017. The audit report was prepared for the use of Cabot in its annual financial and reserves reporting and was completed on January 26, 2018. Cabot's estimates, shown below, are in accordance with the definitions contained in Securities and Exchange Commission (SEC) Regulation S-X, Rule 4-10(a) as shown in the Appendix.

Reserves and Future Net Revenues as of December 31, 2017

Reserves Category	Net Reserves			Future Net Revenues
	Oil and Condensate, MBbls.	NGL, MBbls.	Gas, Bcf	Undiscounted, M$	Discounted at 10% Per Year, M$
Proved Developed	27,251	3,815	6,001	9,172,034	4,121,610
Proved Undeveloped	26,466	4,720	3,352	4,448,470	1,844,074
Total Proved	53,717	8,535	9,353	13,620,504	5,965,684

M&L prepared independent estimates of 100 percent of the proved reserves reported by Cabot. Based on M&L’s investigations and subject to the limitations described hereinafter, it is M&L’s judgment that (1) the reserves estimation methods employed by Cabot were appropriate, and its classification of such reserves was appropriate to the relevant SEC reserve definitions, (2) its reserves estimation processes were comprehensive and of sufficient depth, (3) the data upon which Cabot relied were adequate and of sufficient quality, and (4) the results of those estimates and projections are, in the aggregate, reasonable.

Cabot’s reserves estimates were based on decline curve extrapolations, material balance calculations, volumetric calculations, analogies, or combinations of these methods for each well, reservoir, or field. Proved undeveloped reserves were assigned to some locations offset by more than one location from existing production. These proved undeveloped reserves are supported by seismic data and geological cross-sections that appropriately demonstrate reservoir continuity with a high degree of certainty. All proved undeveloped reserves are scheduled to be developed within five years of initial booking. Reserves estimates from volumetric calculations and from analogies are often less certain than reserves estimates based on well performance obtained over a period during which a substantial portion of the reserves were produced.

All reserves discussed herein are located within the Continental United States and Canada. Gas volumes were estimated at the appropriate pressure base and temperature base that are established for each well or field by the

applicable sales contract or regulatory body. Total gas reserves were obtained by summing the reserves for all the individual properties and are therefore stated herein at a mixed pressure base.

Cabot represents that the future net revenues reported herein were computed based on prices for oil and gas, utilizing the 12-month averages of the first-day-of-the-month prices, and are in accordance with SEC guidelines. Cabot used benchmark prices of $51.34 per barrel based on the West Texas Intermediate Spot Price at Cushing, Oklahoma and $2.976 per MMBtu based on the Henry Hub Spot Price for its reserves estimates. The average realized prices used in this report for proved reserves, after appropriate adjustments, were $49.26 per barrel for oil, $2.33 per Mcf for gas, and $20.64 per barrel for NGLs. The present value of future net revenues was computed by discounting the future net

revenues at 10 percent per year. Estimates of future net revenues and the present value of future net revenues are not intended and should not be interpreted to represent fair market values for the estimated reserves.

In making its projections, Cabot included cost estimates for well abandonment and well site reclamations. Cabot's estimates include no adjustments for production prepayments, exchange agreements, gas balancing, or similar arrangements. M&L was provided with no information concerning these conditions and it has made no investigations of these matters as such was beyond the scope of this investigation.

In conducting this evaluation, M&L relied upon, without independent verification, Cabot’s representation of (1) ownership interests, (2) production histories, (3) accounting and cost data, (4) geological, geophysical, and engineering data, and (5) development schedules. These data were accepted as represented and were considered appropriate for the purpose of the audit report. To a lesser extent, nonproprietary data existing in the files of M&L, and data obtained from commercial services were used. M&L employed all methods, procedures, and assumptions considered necessary in utilizing the data provided to prepare the report.

The evaluations presented in this report, with the exceptions of those parameters specified by others, reflect M&L’s informed judgments and are subject to the inherent uncertainties associated with interpretation of geological, geophysical, and engineering information. These uncertainties include, but are not limited to, (1) the utilization of analogous or indirect data and (2) the application of professional judgments. Government policies and market conditions different from those employed in this study may cause (1) the total quantity of oil, natural gas liquids, or gas to be recovered, (2) actual production rates, (3) prices received, or (4) operating and capital costs to vary from those presented in this report. At this time, MLL is not aware of any regulations that would affect Cabot’s ability to recover the estimated reserves.

Miller and Lents, Ltd. is an independent oil and gas consulting firm. No director, officer, or key employee of Miller and Lents, Ltd. has any financial ownership in Cabot. Our compensation for the required investigations and preparation of this report is not contingent on the results obtained and reported, and we have not performed other work that would affect our objectivity. Production of this report was supervised by Katie M. Reinaker, P.E., an officer of the firm who is a licensed Professional Engineer in the State of Texas and is professionally qualified, with more than nine years of relevant experience, in the estimation, assessment, and evaluation of oil and gas reserves.

If you have any questions regarding this evaluation, or if we can be of further assistance, please contact us.

Very truly yours,

MILLER AND LENTS, LTD.

Texas Registered Engineering Firm No. F-1442

By /s/ James A. Cole,_____________________

James A. Cole, P.E.

Senior Consultant

By /s/ Katie M. Reinaker___________________

Katie M. Reinaker, P.E.

Senior Vice President

Appendix

Reserves Definitions In Accordance With

Securities and Exchange Commission Regulation S-X

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.

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).

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.

1. 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.

2. 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.

3. 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.

4. 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.

5. 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.

Developed Oil and Gas Reserves

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

1. 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

2. 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.

1. 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.

2. 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.

3. 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 below, or by other evidence using reliable technology establishing reasonable certainty.

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:

1. Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

2.     Same environment of deposition;

3.     Similar geological structure; and

4.     Same drive mechanism.

Reservoir properties must, in aggregate, be no more favorable in the analog than in the reservoir

of interest.

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.

1. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

2. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

3. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

4. See also guidelines in Items 4 and 6 under Possible Reserves.

Possible Reserves

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

1. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

2. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

3. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

4. The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

5. Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not

been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

6. Pursuant to Item 3 under Proved Oil and Gas Reserves, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.