Eclipse Resources (ECR) Reports Proved Reserves and Offers Operational and Financial Update

Eclipse Resources Corporation (NYSE: ECR) (the “Company” or “Eclipse Resources”) today, in advance of the Company’s Analyst Day, provided an update on its fourth quarter and full year 2016 production, year-end 2016 proved reserves, its 2017 capital budget and its spring borrowing base redetermination. In addition, Eclipse provided an update to Company type curve assumptions.

Highlights of the release include:

• Net production for the fourth quarter 2016 averaged 255 MMcfe per day, which was above the high end of our previously issued guidance range
• Net production for the full year 2016 averaged 229 MMcfe per day, which was above the midpoint of our previously issued guidance range
• Year-End 2016 proved reserves increased by 35% to 469 Bcfe based on SEC pricing, and by 108% to 1.2 Tcfe based on forward strip pricing
• The Company’s Board of Directors established an initial capital budget for the full year 2017 of approximately $300 million1, which is expected to be funded substantially from the Company’s cash balance and cash flows
• The Company has updated its Utica Condensate and Utica Rich Gas type curve assumptions, resulting in an increase of EUR’s approximately 16% and 22% respectively based on the results of recently completed wells using the Company’s “Gen3” completion design
• The Company recently received commitments subject to final documentation supporting an increase in its borrowing base to $175 million from $125 million, while extending the maturity of the credit facility to January of 2020

Production

The Company achieved fourth quarter 2016 average net production of 255 MMcfe per day, above the high end of the Company’s guidance range. The Company also achieved full year 2016 average net production of 229 MMcfe per day, above the midpoint of the Company’s guidance range. For the fourth quarter of 2016, the Company’s production mix was 71% natural gas, 18% natural gas liquids and 11% oil, while the production mix for the full year 2016 was 73% natural gas, 17% natural gas liquids and 10% oil.

Proved Reserves

The Company has recently received its annual reserve report as prepared by its independent reservoir engineering firm, Netherland, Sewell & Associates, Inc., which estimated the Company’s proved reserves at December 31, 2016 to be 469.4 Bcfe, a 35% increase compared to proved reserves at December 31, 2015. This increase in reserves was driven mainly by an increase in proved developed producing reserves related to new wells coming on production during 2016 and from the addition of incremental proved undeveloped reserves. SEC prices for reserves were calculated as of December 31, 2016 and among other items calibrated for quality, energy content and market differentials with the average adjusted product price weighted by production over the remaining lives of the properties being $34.57 per Bbl for oil, $2.195 per Mcf for natural gas, and $13.43 per Bbl of NGLs.

Using SEC prices, which are not indicative of current forward prices, the pre-tax present value discounted at 10% of the December 31, 2016 proved reserves (“PV10”) was $206.0 million, an approximate 3% decrease over the year-end 2015 reported value of PV10 of $212.9 million. This decrease in PV10 is primarily the result of substantially lower commodity prices used in the calculation of 2016 proved reserves using SEC pricing as compared to the calculation of 2015 proved reserves which utilized $38.20 per bbl for oil, $2.52 per mcf for natural gas and $12.88 per bbl of NGLs.

Utilizing forward New York Mercantile Exchange (“NYMEX”) pricing as of December 31, 2016, the PV10 value would be approximately $608.3 million and the proved reserve volumes would be 1.2 Tcfe. This represents a value increase of $327.7 million, or over 117%, and a volume increase of over 634.7 Bcfe, or 108%, relative to our reserves at year end 2015 using year-end 2015 NYMEX forward prices.

For the year 2016, the Company estimates that its drill bit only finding and development cost, including revisions, was $0.70 per Mcfe while the all sources finding and development cost for estimated proved reserve additions, including revisions was $0.91 per Mcfe. The finding and development costs are based on the Company’s preliminary and unaudited 2016 capital costs. Final capital costs will be provided in the Company’s Annual Report on Form 10-K for the year ended December 31, 2016.

2017 Capital Budget

The Board of Directors has approved an initial capital budget for 2017 of approximately $300 million1. This budget includes approximately $261 million for drilling and completions activities, $33 million for land activities and $6 million for other capital requirements. The initial capital budget assumes the drilling of 19 net (22 gross) horizontal Utica Shale wells, and completion of 19 net (20 gross) horizontal Utica Shale wells. The budget also includes the drilling and completion of 1.9 net (2.0 gross) Marcellus wells. The wells to be drilled in 2017 are expected to average approximately 13,300 feet in lateral length. Included in this well count are eleven “Super-Lateral” wells with lateral extensions planned to be in excess of 15,000 feet, three of which will be located in the Company’s Utica Dry gas acreage area, and eight in the Company’s Utica Condensate acreage area. The 2017 Capital Budget is expected to be substantially funded through internally generated cash flows and the Company’s current cash balance.

Type Curve Assumptions

Based primarily on the results generated through the implementation of its Generation 3 completion design, the Company has increased its Utica Condensate and Utica Rich Gas type curve EURs. The Utica Condensate type curve EUR has increased to 1.1 Bcfe per 1,000 foot of lateral from 0.9 Bcfe per 1,000 foot of lateral or approximately 16%, while the Rich Gas type curve EUR has increased to 2.2 Bcfe per 1,000 foot of lateral from 1.8 Bcfe per 1,000 foot of lateral, or approximately 22% at year-end 2016 strip pricing. These type wells are both estimated to generate IRR’s in excess of 60% assuming current forward NYMEX strip pricing and the Company’s 2017 expected well costs. The Company now estimates it has over 16 years of highly economic drilling inventory at its planned 2017 pace of development. As part of this type curve revision process, the Company has adjusted the location of each type curve area and recalculated the associated acreage in each type curve band while incorporating all recent acreage acquisitions and divestitures. The Company’s current acreage footprint of 112,000 net acres, an increase from 105,000 net acres previously reported, consists of acreage which is 41% in the Utica Dry Gas type curve area, 38% in the Utica Condensate area, 13% in the Marcellus Condensate area1 and 8% in the Utica Rich gas area.

In December, the Company began the process of turning to sales its first Generation 3 Dry Gas Utica wells. These five wells have exhibited similar performance improvements as the Generation 3 Utica Condensate wells, and are flowing above current type curve expectations at the Company’s target weekly pressure decline rate. The Company plans to continue to evaluate these wells for an additional three to six months before making an assessment on their implication to the Company’s existing Dry Gas type curve assumptions.

Financial Update

The Company is pleased to announce that it recently completed its spring borrowing base redetermination process and has received commitments subject to final documentation supporting an increase in its borrowing base from $125 million to $175 million. As part of this process, the Company and bank group agreed to extend the maturity of the revolving credit facility to January 2020. Assuming this transaction closes under the terms as currently anticipated, the Company estimates that it exited the year with $342 million in liquidity, which consisted of cash on hand of approximately $202 million and this undrawn revolver net of $34 million of letters of credit.

Guidance

The Company issued the following first quarter and full year 2017 guidance in the table below:

Analyst Day

Eclipse Resources will host its 2017 Analyst Day on Wednesday, February 8th at the Intercontinental Barclay Hotel in New York City. A live audio webcast of the event will begin at 9:00 am (Eastern) and can be accessed on the “Investors” section of the Eclipse Resources website at www.eclipseresources.com. The Company plans to post the Analyst Day Presentation to the “Investors” section of the Company’s website just prior to the event.

Non-GAAP Disclosure

Year-end pre-tax PV10 value is a non-GAAP financial measure as defined by the SEC. Eclipse Resources believes that the presentation of pre-tax PV10 value is relevant and useful to the Company’s investors because it presents the discounted future net cash flows attributable to Eclipse Resources’ reserves prior to taking into account corporate future income taxes and the Company’s current tax structure. Eclipse Resources further believes investors and creditors use pre-tax PV10 value as a basis for comparison of the relative size and value of the Company’s reserves as compared with other companies.

The GAAP financial measure most directly comparable to pre-tax PV10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). Eclipse Resources is not yet able to provide a reconciliation of pre-tax PV10 to Standardized Measure because the discounted future income taxes associated with the Company’s reserves is not yet calculable. Eclipse Resources expects to include a full reconciliation of pre-tax PV10 to Standardized Measure in its Annual Report on Form 10-K for the year ended December 31, 2016.

Cash General and Administrative Expenses

Cash General and Administrative Expenses is a non-GAAP financial measure used by the Company in the Guidance Table to provide a measure of Administrative expenses used by many investors and published research in making investment decisions and evaluating operational trends of the Company. See the table below for a reconciliation of Cash General and Administrative Expenses and General and Administrative Expenses.

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