As of December 31, 2014,2016, we held leasehold interests in approximately 185,000232,000 gross (180,000(213,000 net) acres in the Utica Shale.

The Ohio Department of Natural Resources reported that in the Utica Shale in Ohio, as of February 7, 2015,December 31, 2016, there were 7401,472 producing horizontal wells, 335256 horizontal wells that had been drilled but were not yet completed or connected to a pipeline, 27319 horizontal wells that were being drilled and an additional 451460 horizontal wells that had been permitted.

Recently, the application of horizontal drilling, combined with multi-staged hydraulic fracturing to create permeable flow paths from shale units into wellbores, has resulted in increased drilling activity and production in the Devonian-age Marcellus Shale and the Ordovician-age Utica Shale in the Appalachian Basin states of Pennsylvania, West Virginia, Southern New York and Eastern Ohio. This proven technology has potential for application in other shale units which extend across much of the Appalachian Basin region.

The Utica Shale is estimated to be thicker and more geographically extensive than the Marcellus Shale. The source rock portion of the Utica Shale underlies portions of Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, West Virginia and Virginia in the United States and is also present beneath parts of Lake Ontario, Lake Erie and Ontario, Canada. Throughout this area, the Utica Shale ranges in thickness from less than 100 feet to over 500 feet. There is a general thinning from east to west.

The Utica Shale is also significantly deeper than the Marcellus Shale. In some parts of Pennsylvania, the Utica Shale is estimated to be over two miles below sea level and up to 7,000 feet below the Marcellus Shale. However, the depth of the Utica Shale decreases to the west into Ohio and to the northwest under the Great Lakes and into Canada to less than 2,000 feet below sea level.

There are standard land oil and natural gas processing facilities in the Utica Shale. Our facilities located at well site pads include storage tank batteries, oil/gas/water separation equipment, vapor recovery units, line heaters, compression emission control devices and applicable metering.

We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2014,2016, had spud 151268 gross wells, 101219 of which were completed and were producing. In 2014,2016, we spud 8550 gross (67.2(43.5 net) wells, of which 3616 were completed as producing wells and are productive, two were non-productive, and as of December 31, 2014, 412016, 26 were in various stages of completion and six were still being drilled. We commenced sales from 54 gross wells (40.2 net wells) in the Utica Shale during 2016. During 20152017 (through February 13, 2015)10, 2017), we had spud fiveten gross (four(9.2 net) wells during 2015wells. As of which three were in various stagesFebruary 10, 2017, four of completion and two were still drilling. In addition, 110 gross (13.3 net) wells were drilled by other operators on our Utica Shale acreage during 2014.these

We currently intend to drill 87 to 97 gross (67 to 74 net) horizontal wells, and commence sales from 72 to 80 gross (61 to 67 net) horizontal wells, on our Utica Shale acreage in 2017. We currently anticipate 30 to 34 gross (10 to 11 net) horizontal wells will be drilled, and sales commenced from 42 to 46 gross (nine to 10 net) horizontal wells, by other operators on our Utica Shale acreage during 2015.2017. We currently anticipate our 2017 capital expenditures to be $645.0 million to $690.0 million related to our operated and non-operated Utica Shale activities. As of February 25, 2015,10, 2017, we had foursix operated horizontal rigs drilling in the play, but plan to release one of these rigs by the end of the first quarter of 2015.play.

The WCBB field is located approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. We own a 100% working interest (80.108% net revenue interest, or NRI), and are the operator, in depths above the base of the 13900 Sand which is located at 11,320 feet. In addition, we own a 40.40% non-operated working interest (29.95% NRI) in depths below the base of the 13900 Sand, which is operated by Chevron Corporation. Our leasehold interests at WCBB contain 5,668 gross acres.

Texaco, now Chevron Corporation, drilled the discovery well in this field in 1940 based on a seismic and gravitational anomaly. WCBB was subsequently developed on an even 160-acre pattern for much of the remainder of the decade. Developmental drilling continued and reached its peak in the 1970s when over 300 wells were drilled in the field. Of the 1,077 wells drilled as of December 31, 2014,2016, 973 were completed as producing wells. From the date of our acquisition of WCBB in 1997 through December 31, 2014,2016, we drilled 265 new wells, 233 of which were productive, for an 88% success rate. As of December 31, 2014,2016, estimated field cumulative gross production was 196.8 MMBOE199 MMBO and 237.0237.2 Bcf of gas. Of the 1,077 wells drilled in WCBB as of December 31, 2014, 1222016, 116 were producing, 185145 were shut-in, one was producing intermittently, one was waiting on completion and six were being used as salt water disposal wells. The other 762810 wells have been plugged and abandoned.

WCBB overlies one of the largest salt dome structures on the Gulf Coast. The field is characterized by a piercement salt dome, which created traps from the Pleistocene through the Miocene formations. The relative movements affected deposition and created a complex system of fault traps. The compensating fault sets generally trend northwest to southeast and are intersected by sets having a major radial component. Later-stage movement caused extension over the dome and a large graben system (a downthrown area bounded by normal faults) was formed.

There are over 100 distinct sandstone reservoirs recognized throughout most of the field, and nearly 200 major and minor discrete intervals have been tested. Within the 1,077 wells that had been drilled in the field as of December 31, 2014,2016, over 4,000 potential zones have been penetrated. These sands are highly porous and permeable reservoirs primarily with a strong water drive.

WCBB is a structurally and stratigraphically complex field. All of the proved undeveloped, or PUD, locations at WCBB are adjacent to faults and abut at least one fault. Our drilling programs are designed to penetrate each PUD trap with a new wellbore in a structurally optimum position, usually very close to the fault seal. The majority of these wells have been, and new wells drilled in connection with our drilling programs will be, directionally drilled using steering tools and downhole motors. The tolerance for error in getting near the fault is low, so the complex faulting does introduce the risk of crossing the fault before encountering the zone of interest, which could result in part or all of the zone being absent in the borehole. This, in turn,

We own and operate a production facility at WCBB that includes four production tank batteries, eightseven natural gas compressors, a storage barge facility, a dock, a dehydration unit and a salt water disposal system.

In 2014,2016, at our WCBB field, we recompleted 9154 gross and net wells and spud 29no new wells. As of February 10, 2017, we had recompleted 14 gross and net wells at WCBB. Of the 29 new wells spud at WCBB in 2014, 21 were completed as producers, five were non-productive and, at year end, three were waiting on completion. As of February 13, 2015, we had recompleted seven wells during 20152017 in our WCBB field. Of the 29 wells drilled in 2014, 22 were considered deep wells. The 21 productive wells, with total depths ranging from 2,500 to 10,501 feet, have approximately 894 feet of aggregate apparent net pay.

In the fourth quarter of 2014,2016, our net production at WCBB was approximately 1,810 net1,272 MMcfe, or an average of 19.713.8 MMcfe per day, 100% of which 99% was from oil. During January 2015, our average net daily production at WCBB was approximately 19.0 MMcfe, 100% of whichoil and 1% was from oil. The slight decrease in average net daily production in January 2015 was due to normal production declines.natural gas.

The East Hackberry field in Louisiana is located along the western shore and the land surrounding Lake Calcasieu, 15 miles inland from the Gulf of Mexico. We own a 100% working interest (approximately 80.945%82.04% average NRI) in certain producing oil and natural gas properties situated in the East Hackberry field. As of December 31, 2014,2016, we held beneficial interests in approximately 4,5124,116 acres, including the Erwin Heirs Block, which is located on land, and the adjacent State Lease 50 Block, which is located primarily in the shallow waters of Lake Calcasieu. We licensed approximately 54 square miles of 3-D seismic data covering a portion of the area and have received a processed version of the seismic data.

The East Hackberry field was discovered in 1926 by Gulf Oil Company, now Chevron Corporation, by a gravitational anomaly survey. The massive shallow salt stock presented an easily recognizable gravity anomaly indicating a productive field. Initial production began in 1927 and has continued to the present. The estimated cumulative oil and condensate production through 20142016 was over 4,037 MBOE4,758 MBO and 331.8332 Bcf of casinghead gas production. A total of 269 wells have been drilled on our portion of the field. As of December 31, 2014, 392016, 25 wells had daily production, 107119 were shut-in and three had been converted to salt water disposal wells. The remaining 120122 wells had been plugged and abandoned.

The Hackberry field is a major salt intrusive feature, elliptical in shape as opposed to a classic “dome,” divided into east and west field entities by a saddle. Structurally, our East Hackberry acreage is located on the eastern end of the Hackberry salt ridge. There are over 30 pay zones at this field. The salt intrusion formed a series of structurally complex and steeply dipping fault blocks in the Lower Miocene and Oligocene age rocks. These fault blocks serve as traps for hydrocarbon accumulation. Our wells currently produce from perforations found between 5,100 and 12,200 feet.

We have a field office that serves both the East and West Hackberry fields. In addition, we own and operate three production facilities at East Hackberry that include two land based tank batteries, a production barge, fivethree natural gas compressors, dehydration units and salt water disposal systems.

There are numerous uncertainties associated with estimating quantities of proved reserves and in projecting future rates of production and timing of expenditures. The reserve information herein represents estimates prepared by (i) Netherland, Sewell & Associates, Inc., or NSAI, with respect to our Utica Shale acreage at December 31, 2016 and 2015, our WCBB and Hackberry fields at each of December 31, 2016, 2015 and 2014, and our Niobrara field at December 31, 2015 and 2014, (ii) Ryder Scott with respect to our Utica Shale acreage at December 31, 2014 2013 and 2012, (ii) Netherland, Sewell & Associates, Inc., or NSAI, with respect to our WCBB, Hackberry and Niobrara fields at each of December 31, 2014, 2013 and 2012 and (iii) our personnel with respect to our overriding royalty and non-operated interests at December 31, 2016, 2015 and 2014 2013 and 2012.our Niobrara field at December 31, 2016. Petroleum engineering is not an exact science. Information relating to our proved oil and natural gas reserves is based upon engineering estimates. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, future site restoration and abandonment costs, the assumed effects of regulations by governmental agencies and assumptions concerning future oil and natural gas prices, future operating costs, severance and excise taxes, capital expenditures and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material.

Estimates of reserves as of year-end 2014, 20132016, 2015 and 20122014 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2014, 20132016, 2015 and 2012,2014, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for undeveloped acreage. The reserve estimates represent our net revenue interest in our properties.

The present value of future net revenues from our proved reserves is not necessarily the same as the current market value of our estimated oil and natural gas reserves. We base the estimated discounted future net revenue from our proved reserves for 2014, 20132016, 2015 and 20122014 on an average price equal to the unweighted arithmetic average of prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2014, 20132016, 2015 and 2012,2014, respectively, in accordance with the revised guidelines of the SEC applicable to reserves estimates for such years. However, actual

Actual future net revenues from our oil and natural gas properties will also will be affected by factors such as:

The timing of both our production and our incurrence of costs in connection with the development and production of oil and natural gas properties will affect the timing of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit

Approximately 51.4%63.0% of our total estimated proved reserves at December 31, 2014,2016, were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, further decreases in commodity prices or increases in costs to drill and develop such reserves will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

There are numerous uncertainties in estimating quantities of bitumen reserves and resources, and the indicated level of reserves or recovery of bitumen may not be realized. In general, estimates of economically recoverable bitumen reserves and the future net cash flow from such reserves are based upon a number of factors and assumptions made as of the date on which the reserve and resource estimates were determined, such as geological and engineering estimates which have uncertainties, the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially.

Estimates with respect to reserves and resources that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history may result in variations in the estimated reserves. Reserve and resource estimates may require revision based on actual production experience. Reserve and resources estimates are determined with reference to assumed oil prices and operating costs. Market price fluctuations of oil prices may render uneconomic the recovery of certain grades of bitumen. The actual gravity or quality of bitumen to be produced from Grizzly's lands cannot be determined at this time.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of natural gas lines and transportation barges owned by third parties. In general, we do not control these transportation facilities and our access to them may be limited or denied. A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. We are at particular risk with respect to oil and natural gas produced at our WCBB field and from our Utica Shale acreage. In October 2006, for example, a natural gas line in our WCBB field operated by our natural gas purchaser was ruptured by a third party contractor, requiring the field to be shut in for approximately seven weeks until the line could be repaired. Further, we are dependent on our oil purchaser to provide the barges necessary to transport our oil production from the WCBB field. With respect to our Utica Shale acreage where we are focusing a significant portionsubstantially all of our exploration and development activity, historically there has been no or only limited infrastructure in this area and the commencement of production from our initial and subsequent wells on our Utica Shale acreage has been delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider.

Our largest fields by production are located in Eastern Ohio and approximately five miles off the coast of Louisiana in a shallow bay with water depths averaging eight to ten feet. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available.

We have identified over 1,000 drilling locations on our Ohio, Louisiana Ohio and Western Colorado properties assuming full development of all of our acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, oil and natural gas prices, inclement weather, costs, drilling results and regulatory changes. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

Our drilling activities are subject to many risks. For example, we cannot assure you that new wells drilled by us will be productive or that we will recover all or any portion of our investment in such wells. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient oil or natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or that it can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control, and increases in those costs can adversely affect the economics of a project. Further, our drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

Our operations are subject to all of the hazards and operating risks associated with drilling for and production of oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of natural gas, oil and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. In addition, our operations are subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. We may face liability for environmental damage caused by previous owners of properties purchased by us, which liabilities may or may not be covered by insurance. The occurrence of any of these events could result in substantial losses to us due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

In accordance with what we believe to be customary industry practice, we historically have maintained insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flow. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development and production activities. These laws and regulations may, among other things: (i) require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, producing and other operations; (ii) regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; (iii) limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas and other protected areas; (iv) require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or (v) impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, the risk of accidental and/or unpermitted spills or releases from our operations could expose us to significant liabilities, penalties and other sanctions under applicable laws.

Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

In September 2013, we entered into a compliance agreement with the Ohio Division of Oil and Gas Resources Management, or the Division, concerning aspects of our operations at seven drilling sites in Ohio. We had previously notified the Division of brine contamination at these drilling sites. After receipt of this notification, the Division conducted an investigation and determined that certain contaminants were escaping from underneath the containment liners at these locations. In the compliance agreement, we agreed, among other things, to conduct our production operations in compliance with all requirements of applicable regulations, implement a remediation plan and make a payment of $250,000. We are continuing to work with the Division to fulfillhave fulfilled our obligations under the compliance agreement and have been released from it by the Division. We cannot assure you that we will not be subject to enhance our materials handling protocols. If the Chief ofcompliance agreements with the Division determines that we have failedor other regulatory bodies in the future. Our failure to comply with the conditions set forthany such compliance agreements may result in the compliance agreement, the Chief may suspendsuspension of all or part of our drilling and production operations infor some specified period as well as the Stateimposition of Ohio for a period determined by the Chief, and we could incur additional penalties and costs.

We acquire significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues and for other reasons. In addition, wells that are profitable may not meet our internal return targets, which are dependent upon the current and expected future market prices for oil and natural gas, expected costs associated with producing oil and natural gas and our ability to add reserves at an acceptable cost. Drilling results in our newer oil and liquids-rich shale plays may be more uncertain than in shale plays that are more developed and have longer established production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other shale formations to maximize recoveries will be ultimately successful when used in newly developed shale formations.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage. In addition, to the extent we engage in horizontal drilling, those activities may adversely affect our ability to successfully drill in one or more of our identified vertical drilling locations. Furthermore, certain of the new techniques we are adopting, such as infill drilling and multi-well pad drilling, may cause irregularities or interruptions in production due to, in the case of infill drilling, offset wells being shut in and, in the case of multi-well pad drilling, the time required to drill and complete multiple wells before any such wells begin producing. The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas often have limited or no production history and consequently we are less able to predict future drilling results in these areas.

Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or declines in natural gas and oil prices, the return on our investment in these areas may not be as

We have been an early entrant into the Utica Shale in Eastern Ohio. We spud our first well, the Wagner 1-28H, on our Utica Shale acreage in February 2012 and, as of December 31, 2014, had spud 151 wells, 101 of which were completed and are producing. In 2014, we spud 85 gross (67.2 net) wells, of which 36 were completed as producing wells, two were non-productive and, as of December 31, 2014, 41 were in various stages of completion and six were still being drilled.2012. As of February 13, 2015, we had spud five gross (four net) wells during 2015. As of February 13, 2015, three of these wells were in various stages of completion and two were still being drilled. In addition, 110 gross (13.3 net) wells were drilled by other operators on our Utica Shale acreage during 2014. We currently intend to drill 46 to 52 gross (28 to 32 net) wells on our Utica Shale acreage in 2015 and anticipate an additional 11 to 16 gross (four to six net) wells will be drilled by other operators on our Utica Shale acreage in 2015. While our costs to acquire undeveloped acreage in this emerging play have generally been less than those of later entrants into a developing play, our drilling results in this area are more uncertain than drilling results in areas that are more developed and producing.have been producing for a longer period of time. Since the Utica Shale has limited production history and since we have limited experience drilling in this play, it is difficult to predict our future drilling results. Our cost of drilling, completing and operating wells in this area may be higher than initially expected, and the value of our undeveloped acreage in the Utica Shale may decline if drilling results are unsuccessful. We cannot assure you that unproved property acquired, or undeveloped acreage leased, by us in the Utica Shale or other emerging plays will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.

Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling include, but are not limited to, the following:

Risks that we face while completing our wells include, but are not limited to, the following:

The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

We are not the operator of all of the properties in which we have an interest, and have limited ability to exercise influence over the operations of such non-operated properties or their associated costs. Dependence on the operator and other working interest owners for these projects, and limited ability to influence operations and associated costs, could prevent the realization of targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation

In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

A significant portion of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. While none of our Utica Shale acreage leases are scheduled to expire until 2015, at that time 25%Approximately 19% of our total Utica Shale undeveloped acreage as of December 31, 2014 will be subject to expiration in 2017, with 29%36% of such acreage expiring in 2016, 5%2018, 14% in 2017, 13%2019, 16% in 20182020 and 10%15% thereafter, although our Utica Shale leases generally grant us the right to extend these leases for an additional five-year period. As of December 31, 2014,2016, leases representing 14%25%, 31%13%, 6%, 7% and 24%62%, respectively, of our total Niobrara Formation undeveloped acreage are scheduled to expire in 2015, 2016, 2017, 2018, and thereafter.2019. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such,If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

Reserve estimates at December 31, 2016 were prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio (99% of our proved reserves at December 31, 2016) and our WCBB and Hackberry fields (1% of our proved reserves at December 31, 2016). Reserve estimates at December 31, 2015 were prepared by NSAI with respect to our assets in the Utica Shale in Eastern Ohio and our WCBB, Hackberry and Niobrara fields. Reserve estimates at December 31, 2014 were prepared by Ryder Scott with respect to our assets in the Utica Shale in Eastern Ohio (97% of our proved reserves at December 31, 2014),and by NSAI with respect to our WCBB, Hackberry and Niobrara fields (3%fields. Our personnel prepared reserve estimates with respect to our Niobrara field as well as our overriding royalty and non-operated interests (less than 1% of our proved reservesreserves) at December 31, 2014)2016. At December 31, 2015 and by2014, our personnel prepared reserve estimates with respect to our overriding royalty and non-operated interests (less than 1% of our proved reserves at December 31, 2014)reserves).

Ryder Scott and NSAI areis an independent petroleum engineering firms. Copiesfirm. A copy of theirthe summary reserve reports areis included as Exhibit 99.1 and 99.2, respectively, to this Annual Report on Form 10-K. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with Ryder Scott and NSAI, our independent reserve engineers, to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves relating to our assets in the Utica Shale and our WCBB Hackberry and NiobraraHackberry fields. Our internal technical team members meet with Ryder Scott and NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to Ryder Scott and NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices and operating and development costs and other considerations, including availability and costs of infrastructure and status of permits. Our proved reserves attributable to our other minority interests are prepared internally by our internal staff of petroleum engineers and geoscience professionals. Our

Our proved reserve estimates are prepared in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

The following table sets forth our estimated proved reserves at December 31, 2014, 20132016, 2015 and 2012:2014: