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•	our business strategy;

•	our reserves;

•	our financial strategy, liquidity and capital required for our development program;

•	realized natural gas, natural gas liquid (“NGL”) and oil prices;

•	timing and amount of future production of natural gas, NGLs and oil;

•	our hedging strategy and results;

•	our future drilling plans;

•	competition and government regulations;

•	pending legal or environmental matters;

•	our marketing of natural gas, NGLs and oil;

•	our leasehold or business acquisitions;

•	costs of developing our properties and conducting our gathering and other midstream operations;

•	operations of Rice Midstream Partners LP;

•	monetization transactions, including asset sales to Rice Midstream Partners LP;

•	general economic conditions;

•	credit and capital markets;

•	uncertainty regarding our future operating results; and

•	plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

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•	“Rice Energy,” the “Company,” “we,” “our,” “us” or like terms refer collectively to Rice Energy Inc. and its consolidated subsidiaries, including Rice Drilling B;

•	“Rice Drilling B” refers to Rice Drilling B LLC, a wholly-owned subsidiary of Rice Energy;

•	“RMP” or the “Partnership” refer to Rice Midstream Partners LP (NYSE: RMP);

•	“Rice Midstream OpCo” refers to Rice Midstream OpCo LLC, a wholly-owned subsidiary of RMP;

•	“Midstream Holdings” refers to Rice Midstream Holdings LLC, a subsidiary of Rice Energy;

•	“Marcellus joint venture” refers collectively to Alpha Shale Resources, LP and its general partner, Alpha Shale Holdings, LLC;

•	“PA Water” refers to Rice Water Services (PA) LLC, a subsidiary of RMP;

•	“OH Water” refers to Rice Water Services (OH) LLC, a subsidiary of RMP; and

•	“GP Holdings” refers to Rice Midstream GP Holdings LP, a subsidiary of Rice Energy.

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•	Increased average production from 2014 pro forma production to 552 MMcfe/d in 2015, a 101% increase

•	Achieved significant growth in average midstream throughput to 894 MDth/d, a 122% increase above 2014

•	Closed successful drop down of water services businesses to RMP for $200.0 million

•	Formed Utica Shale midstream joint venture in Ohio in February 2016 with Gulfport Energy Corporation (“Gulfport”)

•	Consummated strategic equity investment of up to $500.0 million in Midstream Holdings in February 2016 (the “Midstream Holdings Investment”)

•	Increased proved reserves 30% to 1.7 Tcfe, compared to year end 2014

•	Increased the borrowing base of our Senior Secured Revolving Credit Facility from $550.0 million to $750.0 million

•	Issued $400.0 million of senior notes due 2023 at 7.25%

•	Increased 2016 hedge position to 566 BBtu/d at a weighted average floor price of $3.11 per MMBtu

•	Completed first Pennsylvania Utica well in Greene County, Pennsylvania

•	Renegotiated gas gathering agreement for acreage acquired from Chesapeake Appalachia, L.L.C. in August 2014 with third party to increase dedication to RMP by 19,000 gross acres

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(1)

Based on our reserve report as of December 31, 2015, we had 40 net drilling locations in the Marcellus Shale associated with proved undeveloped reserves and six net drilling locations in the Marcellus Shale associated with proved developed not producing reserves. We also had 15 net drilling locations in the Ohio Utica Shale associated with proved undeveloped reserves and seven net drilling location in the Ohio Utica Shale associated with proved developed not producing reserves. Please see “Item 2. Properties—Exploration and Production Segment Properties Reserve Data—Determination of Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Item 1A. Risk Factors—Risks Related to Our Business—Our drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our drilling locations.”

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(2)	Ohio Utica Shale net drilling locations gives effect to our working interest in the Ohio Utica Shale after applying unitization and participating interest assumptions described under “Item 2. Properties—Exploration and Production Properties Reserve Data—Determination of Drilling Locations.”

(3)	Net acres in the Pennsylvania Utica Shale and Upper Devonian Shale are not included in the total acreage as the Pennsylvania Utica Shale, Upper Devonian Shale and Marcellus Shale are stacked formations within the same geographic footprint.

(3)	Excludes seven producing wells acquired in our Greene County, Pennsylvania acreage acquisition in August 2014.

•	$285.0 million for drilling and completion in the Marcellus Shale;

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•	$275.0 million for drilling and completion in the Utica Shale; and

•	$80.0 million for leasehold acquisitions.

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•	worldwide and regional economic conditions affecting the global supply of and demand for natural gas, NGLs and oil;

•	the price and quantity of imports of foreign natural gas, including liquefied natural gas;

•	increased associated gas production resulting from higher oil prices and the related increase in oil production;

•	political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

•	the level of global exploration and production;

•	the level of global inventories;

•	prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

•	the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

•	localized and global supply and demand fundamentals and transportation availability;

•	the actions of the Organization of the Petroleum Exporting Countries;

•	weather conditions and natural disasters;

•	technological advances affecting energy consumption;

•	the cost of exploring for, developing, producing and transporting reserves;

•	speculative trading in natural gas derivative contracts;

•	risks associated with operating drilling rigs;

•	increased end-user conservation or conversion of alternative fuels;

•	the price and availability of competitors’ supplies of natural gas and oil and alternative fuels; and

•	domestic, local and foreign governmental regulation and taxes.

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•	our proved reserves;

•	the level of hydrocarbons we are able to produce from existing wells;

•	our access to, and the cost of accessing, end markets for our production;

•	the prices at which our production is sold;

•	our ability to acquire, locate and produce new reserves;

•	the levels of our operating expenses; and

•	our ability to access the public or private capital markets or borrow under our revolving credit facilities.

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•	delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;

•	pressure or irregularities in geological formations;

•	shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

•	equipment failures, accidents or other unexpected operational events;

•	lack of available gathering facilities or delays in construction of gathering facilities;

•	lack of available capacity on interconnecting transmission pipelines;

•	adverse weather conditions, such as blizzards and ice storms;

•	issues related to compliance with environmental regulations;

•	environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•	declines in natural gas prices;

•	limited availability of financing at acceptable terms;

•	title problems; and

•	limitations in the market for natural gas.

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•	sell assets;

•	make loans to others;

•	make investments;

•	enter into mergers;

•	make certain payments;

•	hedge future production or interest rates;

•	incur liens;

•	engage in certain other transactions without the prior consent of the lenders; and

•	pay dividends.

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•	actual prices we receive for oil and natural gas;

•	actual cost of development and production expenditures;

•	the amount and timing of actual production; and

•	changes in governmental regulations or taxation.

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•	production is less than the volume covered by the derivative instruments;

•	the counterparty to the derivative instrument defaults on its contractual obligations;

•	there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or

•	there are issues with regard to legal enforceability of such instruments.

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•	CAA, and analogous state law, which impose obligations related to air emissions;

•	CWA, and analogous state law, which regulate discharge of wastewaters and storm water from some of our facilities into state and federal waters, including wetlands;

•	CERCLA, and analogous state law, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

•	RCRA, and analogous state law, which impose requirements for the handling and discharge of any solid and hazardous waste from our facilities;

•	NEPA, which requires federal agencies to study likely environmental impacts of a proposed federal action before it is approved, such as drilling on federal lands;

•	SDWA, and analogous state law, which restrict the disposal, treatment or release of water produced or used during oil and gas development;

•	ESA, and analogous state law, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and

•	OPA, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulates above ground storage tanks and sets forth liability for spills by responsible parties.

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•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventive and mitigating actions.

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•	environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;

•	abnormally pressured formations;

•	mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

•	fires, explosions and ruptures of pipelines;

•	personal injuries and death;

•	natural disasters; and

•	terrorist attacks targeting natural gas and oil related facilities and infrastructure.

•	injury or loss of life;

•	damage to and destruction of property, natural resources and equipment;

•	pollution and other environmental damage;

•	regulatory investigations and penalties;

•	suspension of our operations; and

•	repair and remediation costs.

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•	unexpected drilling conditions;

•	title problems;

•	pressure or lost circulation in formations;

•	equipment failure or accidents;

•	adverse weather conditions;

•	compliance with environmental and other governmental or contractual requirements; and

•	increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

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•	recoverable reserves;

•	future natural gas, NGL or oil prices and their applicable differentials;

•	operating costs; and

•	potential environmental and other liabilities.

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•	limitations on the removal of directors;

•	limitations on the ability of our stockholders to call special meetings;

•	establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;

•	providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and

•	establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.

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(1)	Marcellus Shale production for the years ended December 31, 2014 and December 31, 2013 was 89.6 Bcfe and 23.0 Bcfe, respectively.

(2)	Ohio Utica Shale production for the year ended December 31, 2014 was 6.9 Bcfe.

(1)

Our historical estimated proved reserves, PV-10 and standardized measure were determined using a 12-month average price for natural gas. The prices used in our reserve report yield weighted average wellhead prices, which are based on index prices and adjusted for energy content, transportation fees and regional price differentials. The index prices and the equivalent wellhead prices are shown in the table below.

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(i)	Index price of our natural gas per MMBtu was $3.67 for our 50% equity investment in our Marcellus joint venture for the year ended December 31, 2013.

(ii)	Weighted average wellhead price of our natural gas per Mcfe was $3.90 for our 50% equity investment in our Marcellus joint venture for the year ended December 31, 2013.

(2)	The table below summarizes historical estimated proved reserves and related PV-10 at December 31, 2013 for our 50% interest in the Marcellus joint venture:

(3)

PV-10 is a non-GAAP financial measure and generally differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Our pre-tax PV-10 at December 31, 2015 and December 31, 2014 was $0.9 billion and $1.7 billion, respectively. We estimate that our historical standardized measure as of December 31, 2015 and December 31, 2014, is approximately $0.9 billion and $1.3 billion, respectively, as adjusted to give effect to the present value of approximately zero and $436 million, respectively, of future income taxes. However, the historical PV-10s and standardized measures of us and our Marcellus joint venture were equivalent, as of December 31, 2013, because our accounting predecessor, Rice Drilling B, and our Marcellus joint venture were not subject to entity level taxation. Accordingly, no provision for federal or state corporate income taxes provided for such periods because taxable income was passed through to Rice Drilling B’s and our Marcellus joint venture’s respective equity holders. However, in connection with the closing of our IPO, as a result of our corporate reorganization, Rice Energy Inc. became the sole member of Rice Drilling B. Rice Energy Inc. is a corporation subject to federal income tax and, as such, our future income taxes are dependent upon our future taxable income. We estimate that our historical standardized measure and the historical standardized measure for our Marcellus joint venture as of December 31, 2013, would have been approximately $269 million and $175 million, respectively, as adjusted to give effect to the present value of approximately $148 million and $117 million, respectively, of future income taxes as a result of our being treated as a corporation for federal income tax purposes. Neither PV-10 nor standardized measure represents an estimate of the fair market value of our natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.

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(1)	The table below summarizes the changes in the estimated historical proved undeveloped reserves during 2013 for our 50% interest in the Marcellus joint venture:

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Undeveloped Net Marcellus Locations – We assume these locations have 7,000 foot laterals and 750 foot spacing between wells which yields approximately 121 acre spacing. In the Marcellus, we apply a 20% risking factor to our net acreage to account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of December 31, 2015, we had approximately 73,000 net acres in the Marcellus which results in 375 undeveloped net locations.

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Undeveloped Net Greene County Locations – We assume these locations have 7,000 foot laterals and 750 foot spacing between wells which yields approximately 121 acre spacing. In Greene County, we apply a 20% risking factor to our net acreage to account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of December 31, 2015, we had approximately 19,000 net acres in Greene County which results in 112 undeveloped net locations.

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Undeveloped Net Upper Devonian Locations - We assume these locations have 7,000 foot laterals and 1,000 foot spacing between wells which yields approximately 161 acre spacing. In the Upper Devonian, we apply a 20% risking factor to our net acreage to account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of December 31, 2015, we had approximately 85,000 net acres prospective for the Upper Devonian which results in 418 undeveloped net locations.

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Undeveloped Net Ohio Utica Locations - We assume these locations have 9,000 foot laterals and 1,000 foot spacing between wells which yields approximately 207 acre spacing. In the Ohio Utica, we apply a 10% risking factor to our net acreage to account for inefficient unitization. As of December 31, 2015, we had approximately 56,000 net acres prospective for the Utica in Ohio which results in 215 undeveloped net locations.

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Undeveloped Net Pennsylvania Utica Locations - We assume these locations have 8,000 foot laterals and 2,000 foot spacing between wells which yields approximately 367 acre spacing. In the Pennsylvania Utica, we apply a 20% risking factor to our net acreage to account for inefficient unitization. As of December 31, 2015, we had approximately 49,000 net acres prospective for the Utica in Pennsylvania which results in 105 undeveloped net locations.

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(1)

Amounts presented in the table above exclude amounts attributable to our Marcellus joint venture for periods prior to the completion of our IPO in January 2014. In connection with our IPO, we acquired the remaining 50% interest in our Marcellus joint venture from our joint venture partner, and as such amounts shown for the year ended December 31, 2014 include 100% of the amounts attributable to our Marcellus joint venture from the date of acquisition forward and amounts for the year ended December 31, 2013 does not include amounts attributable to our Marcellus joint venture. The table below sets forth information regarding production, revenues and realized prices and production costs (excluding the impact of production taxes and impact fees) on a historical basis for the years ended December 31, 2013 for our 50% equity investment in our Marcellus joint venture:

(2)	The effect of hedges includes realized gains and losses on commodity derivative transactions.

(3)

Average costs per Mcfe for the years ended December 31, 2015 and December 31, 2014, as presented, reflects cost attributable to our Exploration and Production segment. On a consolidated basis, the applicable costs per Mcfe as of December 31, 2015 and December 31, 2014, respectively, are as follows: lease operating - $0.22 and $0.26; gathering, compression and transportation - $0.42 and $0.36; production taxes and impact fees - $0.04 and $0.05; general and administrative - $0.51 and $0.63; and depletion, depreciation and amortization - $1.60 and $1.60.

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•	customary royalty interests;

•	liens incident to operating agreements and for current taxes;

•	obligations or duties under applicable laws;

•	development obligations under natural gas leases; or

•	net profits interests.

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(1)	All shares withheld during 2015 were used to offset tax withholding obligations that occur upon the vesting of restricted stock units and delivery of common stock under the terms of our long-term incentive plan.

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(1)

The adjustments for the derivative fair value (gains) losses and net cash receipts on settled commodity derivative instruments have the effect of adjusting net income (loss) for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDAX on a cash basis during the period the derivatives settled.

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(1)

Differential is calculated by comparing the average NYMEX Henry Hub price to our volume weighted average realized price per MMBtu before hedges, including 50% of the volumes sold by our Marcellus joint venture for the period from January 1, 2014 through January 28, 2014, contained within the year ended December 31, 2014. The remainder of the year ended December 31, 2014 reflects 100% of the volumes sold by our Marcellus joint venture.

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•	Lease operating expense. These are the day to day operating costs incurred to maintain production of our natural gas producing wells. Such costs include produced water disposal, maintenance and repairs. Cost levels for these expenses can vary based on supply and demand for oilfield services.

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Gathering, compression and transportation. These are costs incurred to bring natural gas to the market. Such costs include fees paid to third parties who operate low- and high-pressure gathering systems that transport our natural gas. We often enter into firm transportation contracts that secure takeaway capacity that includes minimum volume commitments, the cost for which is included in these expenses.

•	Midstream operation and maintenance. These are costs incurred to operate and maintain our low- and high-pressure natural gas gathering and compression systems and our water services assets used to support well completion activities and to collect and recycle or dispose of flowback and produced water.

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Incentive unit expense. These costs represent non-cash compensation expense for incentive units awarded to certain of our employees by NGP Holdings and Rice Holdings. In connection with our IPO and related corporate reorganization, the holders of incentive units in Rice Energy Appalachia LLC (“Rice Appalachia”) contributed a portion of their incentive units to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. This resulted in the incentive units being deemed to have been modified, and the performance conditions were considered to be probable of occurring. Therefore, their fair values were measured and compensation expense from the date of initial grant through December 31, 2015 has been recognized in the year ended December 31, 2015. The payment obligation as it relates to the incentive units resides with NGP Holdings and Rice Holdings and has not been, and will not be borne by us.

•	General and administrative expense. These costs include overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our exploration and production operations, midstream operations, franchise taxes, audit and other professional fees and legal compliance expenses.

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Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs to each unit of production using the units of production method.

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Interest expense. We have financed a portion of our working capital requirements and property acquisitions with borrowings under our revolving credit facilities and our Notes. As a result, we incur interest expense that is affected by the level of drilling, completion and acquisition activities, as well as fluctuations in interest rates and our financing decisions. We will likely continue to incur significant interest expense as we continue to grow. To date, we have not entered into any interest rate hedging arrangements to mitigate the effects of interest rate changes. Additionally, we capitalized $0.2 million, $0.9 million and $8.0 million of interest expense for the years ended December 31, 2015, 2014 and 2013, respectively.

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Gain on derivative instruments. We utilize commodity derivative contracts to reduce our exposure to fluctuations in the price of natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are recorded at fair value at each balance sheet date with changes in fair value recognized as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

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Income tax expense. We are a corporation under the Internal Revenue Code, subject to federal income taxes at a statutory rate of 35% of pretax earnings. The reorganization of our business in connection with the closing of our IPO, such that it is now held by a corporation subject to federal income tax, required the recognition of a deferred tax asset or liability for the initial temporary differences at the time of our IPO. The resulting deferred tax liability of approximately $162.3 million was recorded in equity at the date of our IPO. Based on our deductions primarily related to intangible drilling costs (“IDCs”) that are expected to exceed 2016 earnings, we expect to generate significant net operating loss assets and deferred tax liabilities. We may report and pay state income or franchise taxes in periods where our IDC deductions do not exceed our taxable income or where state income or franchise taxes are determined on another basis.

•	Our natural gas, oil and NGL sales were $446.5 million, $359.2 million and $87.8 million in the years ended December 31, 2015, 2014 and 2013, respectively.

•	Our production volumes were 201.3 Bcfe, 97.7 Bcfe and 23.0 Bcfe in the years ended December 31, 2015, 2014 and 2013, respectively.

•	Our gathering, compression and water services revenues were $49.2 million, $5.5 million and $0.1 million for the years ended December 31, 2015, 2014 and 2013, respectively.

•	Our per unit cash production costs were $0.68 per Mcfe, $0.67 per Mcfe and $0.79 per Mcfe in the years ended December 31, 2015, 2014 and 2013, respectively.

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•	incur additional indebtedness;

•	sell assets;

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•	make loans to others;

•	make investments;

•	enter into mergers;

•	make or declare dividends;

•	hedge future production or interest rates;

•	incur liens; and

•	engage in certain other transactions without the prior consent of the lenders.

•	a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and

•	a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as such term is defined in the Amended Credit Agreement) based on the trailing twelve month period to consolidated interest expense, of not less than 2.5 to 1.0.

•	incur or guarantee additional debt;

•	redeem or repurchase units or make distributions under certain circumstances;

•	make certain investments and acquisitions;

•	incur certain liens or permit them to exist;

•	enter into certain types of transactions with affiliates;

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•	merge or consolidate with another company; and

•	transfer, sell or otherwise dispose of assets.

•	an interest coverage ratio, which is the ratio of Midstream Holdings’ consolidated EBITDA (as defined within the Midstream Holdings Revolving Credit Facility) to our consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter; and

•	a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.25 to 1.0.

•	incur or guarantee additional debt;

•	redeem or repurchase units or make distributions under certain circumstances;

•	make certain investments and acquisitions;

•	incur certain liens or permit them to exist;

•	enter into certain types of transactions with affiliates;

•	merge or consolidate with another company; and

•	transfer, sell or otherwise dispose of assets.

•	an interest coverage ratio, which is the ratio of the RMP’s consolidated EBITDA (as defined within the revolving credit facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter;

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•	a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.75 to 1.0, and after electing to issue senior unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.0, and, in each case, with certain increases in the permitted total leverage ratio following the completion of a material acquisition; and

•	if RMP elects to issue senior unsecured notes, a consolidated senior secured leverage ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.50 to 1.0.

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(1)

As of December 31, 2015, we had three horizontal drilling rigs under contract, one of which expires in 2016 and two expire in 2017. We also have two tophole drilling rigs under contract, of which one expires in 2016 and one expires in 2018. Any other rig performing work for us is done on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the table above. The values in the table represent the gross amounts that we are committed to pay as operator. However, we will record in our consolidated financial statements our proportionate share of the amounts shown based on our working interest.

(2)	Represents gross retirement costs with no discounting impact.

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1.	Summary of Significant Accounting Policies and Related Matters

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2.	Property, Plant and Equipment

3.	Goodwill

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4.	Long-Term Debt

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•	in connection with any sale or other disposition of all or substantially all of the assets of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary (as defined in the indentures governing the Notes) of the Company;

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in connection with any sale or other disposition of the capital stock of that Guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a Restricted Subsidiary of the Company, such that, immediately after giving effect to such transaction, such Guarantor would no longer constitute a subsidiary of the Company;

•	if the Company designates any Restricted Subsidiary that is a Guarantor to be an unrestricted subsidiary in accordance with the indentures governing the Notes;

•	upon legal defeasance or satisfaction and discharge of the indentures governing the Notes; or

•	if such Guarantor ceases to guarantee any other indebtedness of the Company or a Guarantor under a credit facility, provided no Event of Default (as defined in the indentures governing the Notes) has occurred and is continuing.

•	default in any payment of interest on any Note when due, continued for 30 days;

•	default in the payment of principal of or premium, if any, on any Note when due;

•	failure by the Company to comply with its other obligations under the indentures governing the Notes, in certain cases subject to notice and grace periods;

•	payment defaults and accelerations with respect to other indebtedness of the Company and its Restricted Subsidiaries (as defined in the indentures governing the Notes) in the aggregate principal amount of $25.0 million or more;

•	certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary (as defined in the indentures governing the Notes) or group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary;

•	failure by the Company or Restricted Subsidiary to pay certain final judgments aggregating in excess of $25.0 million within 60 days; and

•	any guarantee of the Notes by a Guarantor ceases to be in full force and effect, is declared null and void in a judicial proceeding or is denied or disaffirmed by its maker.

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•	incur additional indebtedness;

•	sell assets;

•	make loans to others;

•	make investments;

•	enter into mergers;

•	make or declare dividends;

•	hedge future production or interest rates;

•	incur liens; and

•	engage in certain other transactions without the prior consent of the lenders.

•	a current ratio, which is the ratio of consolidated current assets (including unused commitments under the Amended Credit Agreement and excluding non-cash derivative assets) to consolidated current liabilities (excluding current maturities under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and

•	a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX (as such term is defined in the Amended Credit Agreement) based on the trailing 12 month period to consolidated interest expense, of not less than 2.5 to 1.0.

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•	incur or guarantee additional debt;

•	redeem or repurchase units or make distributions under certain circumstances;

•	make certain investments and acquisitions;

•	incur certain liens or permit them to exist;

•	enter into certain types of transactions with affiliates;

•	merge or consolidate with another company; and

•	transfer, sell or otherwise dispose of assets.

•	an interest coverage ratio, which is the ratio of Rice Midstream Holding’s consolidated EBITDA (as defined within the Midstream Holdings Revolving Credit Facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter; and

•	a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.25 to 1.0.

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•	incur or guarantee additional debt;

•	redeem or repurchase units or make distributions under certain circumstances;

•	make certain investments and acquisitions;

•	incur certain liens or permit them to exist;

•	enter into certain types of transactions with affiliates;

•	merge or consolidate with another company; and

•	transfer, sell or otherwise dispose of assets.

•	an interest coverage ratio, which is the ratio of the Partnership’s consolidated EBITDA (as defined within the RMP Revolving Credit Facility) to its consolidated current interest expense of at least 2.50 to 1.0 at the end of each fiscal quarter;

•	a consolidated total leverage ratio, which is the ratio of consolidated debt to consolidated EBITDA, of not more than 4.75 to 1.0, and after electing to issue senior unsecured notes, a consolidated total leverage ratio of not more than 5.25 to 1.0, and, in each case, with certain increases in the permitted total leverage ratio following the completion of a material acquisition; and

•	if the Partnership elects to issue senior unsecured notes, a consolidated senior secured leverage ratio, which is the ratio of consolidated senior secured debt to consolidated EBITDA, of not more than 3.50 to 1.0.

5.	Derivative Instruments

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6.	Fair Value of Financial Instruments

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7.	Rice Midstream Partners LP

8.	Acquisitions

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9.	Financial Information by Business Segment

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10.	Commitments and Contingencies

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11.	Lease Obligations

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12.	Asset Retirement Obligations

13.	Stockholders’ Equity

14.	Incentive Units

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15.	Stock-Based Compensation

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16.	Earnings Per Share

17.	Income Taxes

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18.	Related Party Transactions

19.	New Accounting Pronouncements

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20.	Subsequent Events

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21.	Guarantor Financial Information

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22.	Quarterly Financial Information (Unaudited)

(1)	The sum of quarterly data in some cases may not equal the yearly total due to rounding.

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23.	Supplemental Information on Gas-Producing Activities (Unaudited)

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(1)	Reflects the balances for Rice Drilling B. Amounts presented in the table exclude amounts attributable to our Marcellus joint venture for periods prior to the completion of our IPO in January 2014.

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(1)	Reflects the balances for Rice Drilling B. Amounts presented in the table exclude amounts attributable to our Marcellus joint venture for periods prior to the completion of our IPO in January 2014.

(2)

Does not include the effects of income taxes on future revenues at December 31, 2013 because that period reflects the result of Rice Drilling B, our accounting predecessor, which was and currently is a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to Rice Drilling B’s equity holders. However, in connection with the closing of our IPO, as a result of the corporate reorganization, the Company became the sole member of Rice Drilling B. The Company is a corporation subject to federal income tax and, as such, its future income taxes will be dependent upon its future taxable income. Therefore, the cumulative effect of future income tax expense for the periods presented was included at December 31, 2015 and 2014.

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(1)	Reflects the balances for Rice Drilling B. Amounts presented in the table exclude amounts attributable to our Marcellus joint venture for periods prior to the completion of our IPO in January 2014.

(2)	Reflects the purchase of the remaining 50% interest in the Marcellus joint venture in January 2014 and the Greene County acreage acquisition in August 2014.

(3)

Does not include the effects of income taxes on future revenues at December 31, 2013 because that period reflects the result of Rice Drilling B, our accounting predecessor, which was and currently is a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to Rice Drilling B’s equity holders. However, in connection with the closing of our IPO, as a result of the corporate reorganization, the Company became the sole member of Rice Drilling B. The Company is a corporation subject to federal income tax and, as such, its future income taxes will be dependent upon its future taxable income. Therefore, the cumulative effect of future income tax expense for the periods presented was included at December 31, 2015 and 2014.

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(1)

Does not include the effects of income taxes on future revenues at December 31, 2013 because that period reflects the result of Rice Drilling B, our accounting predecessor, which was and currently is a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to Rice Drilling B’s equity holders. However, in connection with the closing of our IPO, as a result of the corporate reorganization, the Company became the sole member of Rice Drilling B. The Company is a corporation subject to federal income tax and, as such, its future income taxes will be dependent upon its future taxable income.

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Undeveloped Net Marcellus Locations – We assume these locations have 7,000 foot laterals and 750 foot spacing between wells which yields approximately 121 acre spacing. In the Marcellus, we apply a 20% risking factor to our net acreage to account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of December 31, 2015, we had approximately 73,000 net acres in the Marcellus which results in 375 undeveloped net locations.

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Undeveloped Net Greene County Locations – We assume these locations have 7,000 foot laterals and 750 foot spacing between wells which yields approximately 121 acre spacing. In Greene County, we apply a 20% risking factor to our net acreage to account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of December 31, 2015, we had approximately 19,000 net acres in Greene County which results in 112 undeveloped net locations.

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Undeveloped Net Upper Devonian Locations - We assume these locations have 7,000 foot laterals and 1,000 foot spacing between wells which yields approximately 161 acre spacing. In the Upper Devonian, we apply a 20% risking factor to our net acreage to account for inefficient unitization and the risk associated with our inability to force pool in Pennsylvania. As of December 31, 2015, we had approximately 85,000 net acres prospective for the Upper Devonian which results in 418 undeveloped net locations.

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Undeveloped Net Utica Locations - We assume these locations have 9,000 foot laterals and 1,000 foot spacing between wells which yields approximately 207 acre spacing. In the Utica, we apply a 10% risking factor to our net acreage to account for inefficient unitization. As of December 31, 2015, we had approximately 56,000 net acres prospective for the Utica in Ohio which results in 215 undeveloped net locations.

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Undeveloped Net Pennsylvania Utica Locations - We assume these locations have 8,000 foot laterals and 2,000 foot spacing between wells which yields approximately 367 acre spacing. In the Pennsylvania Utica, we apply a 20% risking factor to our net acreage to account for inefficient unitization. As of December 31, 2015, we had approximately 49,000 net acres prospective for the Utica in Pennsylvania which results in 105 undeveloped net locations.

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