Scotia Howard Weil 2017 Energy Conference
March 27 – 28, 2017
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Forward-Looking Statements and Other Disclaimers
FORWARD-LOOKING STATEMENTS
This presentation and the oral statements made in connection therewith may contain “forward looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, regarding Rice Energy’s strategy, future operations, financial position,
estimated revenues and income/losses, projected costs, as amended, prospects, plans and objectives of management are forward-looking statements. These statements often include the words
“could,” “believe,” “anticipate,” “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “project,” “budget,” “potential,” “guidance,” or
“continue” and similar expressions intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Without limiting the generality of
the foregoing, forward-looking statements contained in this presentation specifically include estimates of Rice Energy’s reserves, expectations of plans, strategies, objectives and anticipated
financial and operating results of Rice Energy, including as to Rice Energy’s drilling program, production, hedging activities, capital expenditure levels and other guidance included in this
presentation. These forward-looking statements are based on Rice Energy’s current expectations and assumptions about future events and are based on currently available information as to the
outcome and timing of future events. Rice Energy assumes no obligation to and does not intend to update any forward looking statements included herein. You are cautioned not to place undue
reliance on any forward-looking statements. Rice Energy cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict
and many of which are beyond their control, incident to the exploration for and development, production, gathering and sale of natural gas, natural gas liquids and oil. These risks include, but are
not limited to, commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory
changes; the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital; the timing of development expenditures; risks
relating to joint venture operations; and the other risks described under “Risk Factors” in Rice Energy’s most recent Form 10-K, Form 10-Q and other filings with the Securities and Exchange
Commission. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, Rice Energy’s actual results and plans could differ materially from those
expressed in any forward-looking statements.
This presentation has been prepared by Rice Energy and includes market data and other statistical information from sources believed by Rice Energy to be reliable, including independent
industry publications, government publications or other published independent sources. Some data are also based on Rice Energy’s good faith estimates, which are derived from its review of
internal sources as well as the independent sources described above. Although Rice Energy believes these sources are reliable, it has not independently verified the information and cannot
guarantee its accuracy and completeness.
NON-PROVEN OIL AND GAS RESERVES
The SEC permits oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are reserve estimates that geological and engineering data demonstrate with reasonable
certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions and certain probable and possible reserves that meet the SEC’s definition for
such terms. We may use certain broader terms such as EUR (estimated ultimate recovery of resources), and we may use other descriptions of volumes of potentially recoverable hydrocarbon
resources throughout this presentation that the SEC does not permit to be included in SEC filings. These broader classifications do not constitute reserves as defined by the SEC, and we do not
attempt to distinguish these classifications from probable or possible reserves as defined by SEC guidelines.
Our estimates of EURs have been prepared by our independent reserve engineers. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves
and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones where there has been limited or no drilling history. We include these estimates to
demonstrate what we believe to be the potential for future drilling and production by the company. Actual locations drilled and quantities that may be ultimately recovered from our properties will
differ substantially. In addition, we have made no commitment to drill all of the drilling locations which have been attributed to these quantities. Ultimate recoveries will be dependent upon
numerous factors including actual encountered geological conditions, the impact of future oil and gas pricing, exploration and development costs, and our future drilling decisions and budgets
based upon our future evaluation of risk, returns and the availability of capital and, in many areas, the outcome of negotiation of drilling arrangements with holders of adjacent or fractional interest
leases. Estimates of resource potential and other figures may change significantly as development of our properties provide additional data and therefore actual quantities that may ultimately be
recovered will likely differ from these estimates.
Our forecast and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells, the undertaking and outcome of future
drilling activity and activity that may be affected by significant commodity price declines or drilling cost increases.
Certain of Rice Energy's wells are named after superheroes and monster trucks, some of which may be trademarked. Despite their size and strength, Rice Energy's wells are in no manner affiliated
with such superheroes or monster trucks.
Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale oil and
natural gas resource plays and tight natural gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.
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Non-GAAP Financial Measures
Rice Energy Adjusted EBITDAX and Further Adjusted EBITDAX
Adjusted EBITDAX and Further Adjusted EBITDAX are supplemental non-GAAP financial measures that are used by management and external users of RICE’s consolidated financial statements, such as industry analysts, investors, lenders and
rating agencies. RICE defines Adjusted EBITDAX as net income (loss) before non-controlling interest; interest expense; income taxes; depreciation, depletion and amortization; amortization of deferred financing costs; amortization of intangible
assets; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash stock compensation expense; non-cash incentive unit expense; exploration expenses; and other non-recurring items. RICE defines
Further Adjusted EBIDAX as Adjusted EBIDAX after non-controlling interest and water revenue adjustment. Neither Adjusted EBITDAX nor Further Adjusted EBITDAX is a measure of net income as determined by United States generally
accepted accounting principles, or GAAP.
Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate RICE’s operating performance and compare the results of RICE’s operations from period to period and against its peers without regard to its
financing methods or capital structure. RICE excludes the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within the industry depending upon
accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Management believes Further Adjusted EBITDAX is useful because it allows them to assess the level of consolidated leverage
of the company and compare this level to peers. The adjustments made to Adjusted EBITDAX to calculate Further Adjusted EBITDAX address the intercompany eliminations of items impacting Adjusted EBITDAX as a result of the consolidation of
RMP, the outstanding indebtedness of which is consolidated with that of the company without regard to non-controlling interest. These adjustments include the addition of non-controlling interest as well as a water revenue adjustment
attributable to charges for fresh water delivery services and produced water hauling services provided by RMP to the company, a charge that generates revenue for RMP but does not have a corresponding expense at the company level, as
such costs are capitalized.
Adjusted EBITDAX and Further Adjusted EBITDAX should not be considered as alternatives to, or more meaningful than, net income as determined in accordance with GAAP or as indicators of RICE’s operating performance or liquidity. Certain
items excluded from Adjusted EBITDAX and Further Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic
costs of depreciable assets, none of which are components of Adjusted EBITDAX or Further Adjusted EBITDAX. RICE’s computations of Adjusted EBITDAX and Further Adjusted EBITDAX may not be comparable to other similarly titled measures
of other companies. RICE believes that these measures are a widely followed measures of operating performance used by investors.
RMH Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of the RMH’s financial statements, such as industry analysts, investors, lenders and rating agencies. RMH defines Adjusted
EBITDA as operating income (loss) before incentive unit expense; acquisition expense; impairment of fixed assets; stock compensation expense; depreciation, depletion and amortization; and other non-recurring items. Adjusted EBITDA is not a
measure of operating income as determined by United States generally accepted accounting principles, or GAAP. Management believes RMH Adjusted EBITDA is useful because it allows them to more effectively evaluate RMH’s operating
performance and compare the results of RMH’s operations from period to period without regard to its financing methods or capital structure. RMH excludes the items listed above from operating income (loss) in arriving at Adjusted EBITDA
because these amounts can vary substantially from company to company within the industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.
RMH Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, operating income as determined in accordance with GAAP or as indicators of RMH’s operating performance or liquidity. Certain items excluded
from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital, as well as the historic costs of depreciable assets, none of which are components of
Adjusted EBITDA. RMH’s computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. RICE believes that the measure is a widely followed measures of operating performance used by
investors.
Management has not provided projected RMH net income or a reconciliation of projected RMH Adjusted EBITDA to projected RMH net income, the most comparable financial measure calculated in accordance with GAAP. Management is unable
to project RMH net income because this metric includes the impact of certain non-cash items such as depreciation expense that management is unable to project with any reasonable degree of accuracy without unreasonable effort. Therefore,
management is unable to provide projected RMH net income, or the related reconciliation of projected RMH Adjusted EBITDA to projected net income.
RMP Adjusted EBITDA, Distributable Cash Flow and DCF Coverage Ratio
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of RMP’s consolidated financial statements, such as securities analysts, investors and lenders. Management defines Adjusted
EBITDA as net income (loss) before interest expense, depreciation expense, amortization expense, non-cash stock compensation expense, amortization of deferred financing costs and other non-recurring items. Adjusted EBITDA is not a
measure of net income as determined by GAAP.
Distributable cash flow and DCF coverage ratio are supplemental non-GAAP financial measures that are used by management and external users of RMP’s consolidated financial statements, such as securities analysts, investors and lenders.
Management defines distributable cash flow as Adjusted EBITDA less cash interest expense, and estimated maintenance capital expenditures. Management defines DCF coverage ratio as distributable cash flow divided by total distributions
declared. Distributable cash flow does not reflect changes in working capital balances and is not a presentation made in accordance with GAAP.
Adjusted EBITDA, distributable cash flow and DCF coverage ratio are non-GAAP supplemental financial measures that management and external users of RMP’s consolidated financial statements, such as industry analysts, investors, lenders and
rating agencies, may use to assess the financial performance of RMP’s assets, without regard to financing methods, capital structure or historical cost basis; RMP’s operating performance and return on capital as compared to other companies in
the midstream energy sector, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing or capital structure; RMP’s ability to incur and service debt and fund capital expenditures; the ability of RMP’s assets to generate
sufficient cash flow to make distributions to RMP’s unitholders; and the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.
Management believes that the presentation of Adjusted EBITDA, distributable cash flow and DCF coverage ratio will provide useful information to investors in assessing RMP’s financial condition and results of operations. The GAAP measures
most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by (used in) operating activities. RMP’s non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not
be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all items that
affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA, distributable cash flow or DCF coverage ratio in isolation or as a substitute for analysis of RMP’s results as reported under GAAP.
Because Adjusted EBITDA and distributable cash flow and DCF coverage ratio may be defined differently by other companies in the industry, RMP’s definitions of Adjusted EBITDA, distributable cash flow and DCF coverage ratio may not be
comparable to similarly titled measures of other companies, thereby diminishing its utility.
Management has not provided projected net income or net cash provided by operating activities or reconciliations of its projected Adjusted EBITDA and projected distributable cash flow to projected net income and projected net cash
provided by operating activities, respectively, the most comparable financial measures calculated in accordance with GAAP. Management is unable to project net cash provided by operating activities because this metric includes the impact of
changes in operating assets and liabilities related to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. Management is unable to project these timing differences with any
reasonable degree of accuracy to a specific day, three or more months in advance. Therefore, management is unable to provide projected net cash provided by operating activities, or the related reconciliation of projected distributable cash
flow to projected net cash provided by operating activities. In addition, management is unable to project net income because this metric includes the impact of certain non-cash items such as depreciation expense that management is unable to
project with any reasonable degree of accuracy without unreasonable effort. Therefore, management is unable to provide projected net income, or the related reconciliation of projected Adjusted EBITDA to projected net income.
Further, management does not provide guidance with respect to the intra-year timing of its capital spending, which impact debt and equity and equity earnings, among other items, that are reconciling items between Adjusted EBITDA and net
income. The timing of capital expenditures is volatile as it depends on weather, regulatory approvals, contractor availability, system performance and various other items. Management provides a range for the forecasts of Adjusted EBITDA and
distributable cash flow to allow for the variability in the timing of spending and the impact on the related reconciling items, many of which interplay with each other. Therefore, the reconciliation of Adjusted EBITDA to projected net income is
not available without unreasonable effort.
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RICE Adjusted EBITDAX Reconciliation
($ in thousands)
Adjusted EBITDAX reconciliation to net income (loss):
Net income
Interest expense
Depreciation, depletion and amortization
Impairment of fixed assets
Impairment of goodwill
Impairment of gas properties
Amortization of deferred financing costs
Amoritization of intangible assets
(Gain) Loss on derivative instruments(1)
Twelve Months Ended Twelve Months Ended Twelve Months Ended
December 31, 2014
December 31, 2015
December 31, 2016
(1)
Net cash receipts on settled derivative instruments
Acquisition expense
Non-cash stock compensation expense
Non-cash incentive unit expense
Income tax expense (benefit)
Gain from sale of interest in gas properties
Gain on purchase of Marcellus joint venture
Exploration expense
Loss on extinguishment of debt
Acquisition break-up fee
Other expense
Non-controlling interest attributable to midstream entities
Adjusted EBITDAX(2)
Three Months Ended
December 31, 2016
$219,035
50,191
156,270
—
—
—
2,495
1,156
($267,999)
87,446
322,784
—
294,908
18,250
5,124
1,632
($248,820)
99,627
368,455
23,057
—
20,853
7,545
1,634
($196,605)
25,883
121,323
20,462
—
20,853
3,129
412
(186,477)
(273,748)
220,236
272,775
(18,784)
2,339
193,908
1,235
16,528
36,097
12,118
(953)
—
3,137
—
—
4,380
(23,337)
$431,510
201,071
6,109
21,915
51,761
(142,212)
—
—
15,159
—
(1,939)
6,511
(75,415)
$575,547
34,720
4,938
4,921
6,859
(104,372)
—
—
5,225
—
—
1,384
(19,880)
$202,027
91,600
(203,579)
4,225
7,654
—
121,066
(581)
$246,610
__________________________
Note: See slide 3 for important disclosures regarding non-GAAP financial measures.
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.
2.
The above Adjusted EBITDAX reconciliation deducts the impact of non-controlling interest attributable to midstream entities and excludes the elimination of intercompany water revenues between Rice Energy subsidiaries and Rice Midstream Partners of $19.9 million and $17.2 million
for the three months ended December 31, 2016, respectively, and $75.4 million and $55.9 million for the year ended December 31, 2016, respectively. When adjusting for these impacts, our Further Adjusted EBITDAX is $239.1 million for the three months ended December 31, 2016, and
$706.8 million for the year ended December 31, 2015. Our consolidated net debt to LTM Further Adjusted EBITDAX ratio is 1.5x. Also included in the above reconciliation is the non-controlling interest attributable to Rice Energy Operating LLC, as we view our business on a fully diluted
basis.
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RMP Adjusted EBITDA and DCF Reconciliation
Three Months Ended Twelve Months Ended Twelve Months Ended
December 31, 2016
December 31, 2016
December 31, 2015
($ in thousands)
Reconciliation of Net Income to Adjusted EBITDA and DCF:
Net income
Interest expense
Income tax expense
Depreciation expense
Amortization of intangible assets
Acquisition costs
Non-cash equity compensation expense
Incentive unit expense
Amortization of deferred financing costs
Other expense
Adjusted EBITDA attributable to Water Assets prior to acquisition(1)
Adjusted EBITDA
$34,260
1,562
7,456
412
52
145
1,046
1,292
$121,610
3,931
25,170
1,634
125
2,873
1,479
1,531
$52,495
3,164
5,812
16,399
1,632
4,501
1,044
576
543
$46,225
$158,353
(22,386)
$63,780
Cash interest expense
Estimated maintenance capital expenditures
Distributable cash flow
(1,562)
(2,800)
$41,863
(3,931)
(11,200)
$143,222
(3,146)
(4,480)
$56,154
Total distributions declared
DCF coverage ratio
$26,508
1.58x
$84,285
1.70x
$34,038
1.22x
$46,225
(1,562)
(1,292)
(52)
$158,353
(3,931)
(1,531)
(125)
$63,780
(3,146)
(543)
-
1,295
$44,614
(623,408)
592,995
14,201
7,634
$21,835
1,350
$154,116
(721,087)
581,207
14,236
7,597
$21,833
22,386
(12,453)
$70,814
(379,991)
290,748
(19,237)
26,834
$7,597
Reconciliation of Adjusted EBITDA to Cash:
Adjusted EBITDA
Interest expense
Other income (expense)
Acquisition costs
Adjusted EBITDA attributable to Water Assets prior to acquisition(1)
Changes in operating assets and liabilities
Net cash provided by operating activities
Net cash used in investing activities
Net cash provided by financing activities
Net increase in cash
Cash at the beginning of the period
Cash at the end of the period
__________________________
Note: See slide 3 for important disclosures regarding Non-GAAP financial measures.
1.
Adjusted EBITDA attributable to the Water Assets prior to their acquisition is excluded from our adjusted EBITDA calculation as these amounts are not attributable to our limited partners. For the year ended December 31, 2015, the Adjusted EBITDA attributable to the Water Assets prior
to acquisition was calculated with net income of $7.3 million plus interest expense of $0.8 million, income tax expense of $5.8 million, depreciation expense of $7.0 million, non-cash equity compensation of $0.4 million and $1.0 million of incentive unit expense.
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RMH Adjusted EBITDA Reconciliation
($ in thousands)
Reconciliation of Operating Income to Adjusted EBITDA:
Operating Income
Incentive unit expense
Acquisition expense
Impairment of fixed assets
Stock compensation expense
Depreciation, depletion and amortization
Other expense
Adjusted EBITDA
Twelve Months Ended
December 31, 2016
$13,609
2,335
484
20,292
5,071
5,760
125
$47,676
__________________________
Note: See slide 3 for important disclosures regarding Non-GAAP financial measures.
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PV-10 Reconciliation
PV-10 is a supplemental non-GAAP financial measure and generally differs from standardized measure, the
most directly comparable GAAP financial measure, because it does not include the effects of income taxes
on future net revenues. PV-10 reflects the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production, future development and abandonment costs,
using prices and costs in effect at the determination date, before income taxes, and without giving effect to
non-property-related expenses, discounted to a present value using an annual discount rate of 10% in
accordance with the guidelines of the SEC. Management and others in the industry use PV-10 as a measure
to compare the relative size and value of proved reserves held by companies without regard to the specific
tax characteristics of such entities. Neither PV-10 nor standardized measure represents an estimate of the
fair market value of our natural gas properties.
The following table presents a reconciliation of the non-GAAP financial measure of PV-10 at SEC pricing to
the standardized measure of discounted future net cash flows:
($ i n mi l l i ons)
Reconciliation to PV-10
Standardized measure of discounted future net cash flows
Discounted future net cash flows for income taxes
Di scou nted fu tu re net cash fl ows before i ncome taxes (PV-10)
Twel ve Months Ended
December 31, 2016
Twel ve Months Ended
December 31, 2015
Twel ve Months Ended
December 31, 2014
$1,548
$20
$1,568
$886
—
$886
$1,308
436
$1,744
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Corporate Strategy
Invest in the Core
Protect Returns through Firm Transport & Hedging
Maintain a Strong, Conservative Balance Sheet
Add Value through Midstream
Drive Excellence through Innovation and Stewardship
Create Long-Term Shareholder Value
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Rice Energy Overview
Ticker Symbol
Headquarters
Founded
IPO date
Market cap(1)
Enterprise value(1)
NYSE: RICE
Canonsburg, PA
2007
January 2014
$5.2B
$6.6B
Full-time employees
Management ownership
RICE E&P
Rice Midstream
Holdings LLC
~475
~15%
GP Holdings
(IDRs and LP Interest)
2016 Business Results
Net Appalachian acres
~248,000
4Q16 Net production (MMcfe/d) 1,145
(2)
Net debt/EBITDAX
1.5x
OH Gathering and
Compression
PA Gathering and PA
+ OH Water Business
__________________________
Note: Share price as of March 20, 2017. Share count and balance sheet data as of December 31, 2016. RICE ownership information taken from public filings and includes ownership of executive officers, directors, Rice trust and other affiliate entities as of March 20, 2017.
1.
Presented as of December 31, 2016 and inclusive of the 40,000,000 Rice Energy Operating LLC common units immediately convertible into 40,000,000 shares of Rice Energy Inc. common stock.
2.
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDAX and Further Adjusted EBITDAX and related reconciliations to comparable GAAP financial measures.
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Strong Ownership Culture With Aligned Interests
 Peer leading management ownership drives alignment with shareholders
 Ownership culture permeates the company – 100% of employees receive stock compensation
 92% RICE GP ownership supports alignment and provides upside for RICE shareholders
MANAGEMENT OWNERSHIP(1)
GP OWNERSHIP(2)
$900
18%
92%
$800
$800
16%
$680
$700
12%
$600
10%
$500
8%
$400
6%
$300
4%
2%
0%
$165
Value ($MM)
Ownership (%)
14%
90%
50%
$200
$120
$40
$60
$15
$25
RICE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7
$100
0%
$0
RICE
Peer 1
Peer 2
Peer 3
__________________________
Source: Peer ownership information based on Factset data as of March 20, 2017. RICE ownership information taken from public filings and includes ownership of executive officers, directors, Rice trust and other affiliate entities as of March 20, 2017. Rice outstanding share count is
inclusive of the Rice Energy Operating LLC common units outstanding as of March 20, 2017 that are immediately convertible into shares of Rice Energy common stock.
1.
Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN.
2.
Peers include AR, CNX and EQT,
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Two Streams of Low-Risk, Economic Growth
RICE UPSTREAM (E&P)






Production (MMcfe/d)
RICE is a technical leader in developing unconventional resource plays
248
552
141
~248,000 core acres in Marcellus and Utica, 100% de-risked, ~80% undeveloped
148
274
4 horizontal rigs actively developing core Marcellus and Utica Shales
4Q16 production of 1,145 MMcfe/d; ~75% CAGR since IPO
2014 2015 2016
RICE MIDSTREAM





831
Top 20 producer of US natural gas; reached 1 Bcfe/d organic production with
fewer wells vs. Appalachia peers
Over 1,100 identified locations with ~95% IRRs at strip pricing(1)
Net Acres (000’s)
2014 2015 2016
Throughput (MDth/d) Dedicated Acres (000’s)
377
1,691
RICE has built a leading midstream company in the Appalachian basin
One of the largest core dry gas dedications: ~377,000 acres from top-tier producers
894
~10 rigs drilling on dedicated acreage
135
4Q16 throughput of 1,203 MDth/d; ~60% CAGR since IPO
145
401
Potential midstream value of ~$2.5 - $3.2B(2)
2014 2015 2016
2014 2015 2016
__________________________
1.
Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice’s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Strip pricing as of
February 10, 2017 based on weighted average of undeveloped locations; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 17.3 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.
2.
Please see slide titled “Significant Unrealized Midstream Value Embedded Within RICE” for a detailed explanation.
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The Premier Appalachian Energy Company
UPSTREAM (E&P)
 ~248,000 acres in the Marcellus and
Utica cores
PA
OH
WV
 Belmont, Washington and Greene
Counties in PA and OH
 ~1,100 locations with ~95% IRRs(1)
 2017E net production = 1.3 Bcfe/d
Utica Core
Marcellus
Core
RICE MIDSTREAM HOLDINGS
RICE MIDSTREAM PARTNERS
 ~162,000 acres dedicated by RICE, GPOR,
CNX
 PA Gathering + PA and OH Water Services
 Rice Olympus Midstream - central
Belmont, 100% owned by RICE
 RICE subsidiary owns 28% of LP Units, 100% of
GP + IDRs
 Strike Force Midstream – eastern Belmont
and central Monroe, 75% owned by RICE
 ~215,000 acres dedicated by RICE and EQT
 2017E
EBITDA(2)
 2017E EBITDA(2) = $193MM
= $90MM
 4Q16 throughput = 1.2 MMDth/d
 4Q16 throughput = 904 MDth/d
 2017E 20% distribution growth + 1.4x coverage
__________________________
1.
Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice’s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Strip pricing as of
February 10, 2017 based on weighted average of undeveloped locations; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 17.3 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.
2.
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA.
12
www.riceenergy.com
Ad(Vantage) RICE: A Track Record of Doing What We Say We’ll Do
2014 (IPO)
2015
Net Production
(MMcfe/d)
274
552
E&P Opex
($/Mcfe)
$1.07
E&P Capex
($MM)
2016
831
↑5%
$1.00
$0.98
↓3%
$830
$740
$686
↓7%
Net Acres Added
~51,000
~7,000
RMH Throughput
(MDth/d)
--
247
708
↑4%
$248
$105
↓25%
RMH Capex
($MM)
~100,000
__________________________
Note: Creative headline inspiration courtesy of CapitalOne. E&P operating expense includes lease operating, gathering and compression, firm transportation and production taxes. Percent beat based on midpoint of 2016 guidance.
13
Beat
Guidance
www.riceenergy.com
2017 Guidance: Core Investments, High Growth and Low Leverage
Budget ($MM)
$1,035
E&P - $1,035MM D&C Budget
 1,290 – 1,355 MMcfe/d net production (~93%
Appalachia, ~60% reported YoY growth, ~45%
organic YoY production growth)
 Budget assumes 10 - 15% service cost inflation
 ~90% hedged in 2017 at weighted average
NYMEX floor price of $3.17/MMBtu
 Exit 2017 E&P leverage ~1.5x
 Funded primarily with cash flow
Funding (%)(3)
$150
Non-Op Utica
$300
Operated
Utica
$585
Marcellus
30%
Cash
70%
Projected
Cash Flow(4)
$315
RMH - $315MM Budget(1)
$75
 $85 – 95MM EBITDA(1)(2) (~90% YoY EBITDA
growth)
 Budget primarily composed of long-term
investments in gathering trunklines and
compression
 Exit 2017 RMH leverage of ~2.25x
$240
2017 Gathering
Laterals
Trunkline and
Compression
55%
Credit Facility
15%
Cash
10%
LP + IDRs(5)
20%
Projected
Cash Flow(4)
__________________________
1.
2.
3.
4.
5.
RMH capital budget and Adjusted EBITDA includes our 75% proportional ownership in Strike Force. Giving effect to Gulfport Midstream’s 25% ownership interests of Strike Force, we expect a range of $95 – 105MM for 2017 Adjusted EBITDA.
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA.
Projected funding excludes potential drop down proceeds.
Projected cash flow based on strip pricing as of February 10, 2017 and 2017 guidance assumptions.
Based on 20% estimated distribution growth.
14
www.riceenergy.com
Investments Create Significant Value, Funded by Strong Balance Sheet




Land – expect to add
10,000 – 15,000 net infill
acres in 2017
Midstream – drives
$2.5B+ of potential drop
downs and GP value
Leverage – RICE 2017E
E&P leverage of 1.5x is
well below peer
average of 2.4x and
consistent with large
cap oil peers’ average
of ~1.6x
RMH Funding
E&P Funding
Land and Midstream –
unique to RICE, adds
significant value and
primarily funded by
cash, cash flow(1) and
drop proceeds(2)
$35
$100
$225
$70
$100
$725
$315
$1,035
$95
$400
$50
Cash on Hand Projected Cash Drop Proceeds (2)
Flow (1)
Revolver
E&P Capex
Cash on Hand Projected CF + Drop Proceeds(2) Revolver
Distributions(1)
RMH Capex
E&P Leverage Profile
4.0x
3.6x
3.0x
2.0x
2.4x
1.8x
1.5x
~ 1.5x
RICE 2017E
RICE 2018E+
1.6x
1.0x
–
RICE 2016
__________________________
Note: Peer data based on Factset estimates as of March 20, 2017.
1.
Projected cash flow based on strip pricing as of February 10, 2017 and 2017 guidance assumptions.
2.
Represents previously guided management estimate of proceeds based on 1/3rd ROM drop down. Actual drop structure and proceeds are subject to change.
3.
Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN.
4.
Large cap oil peers include CXO, EOG, OXY and PXD.
15
(3)
(3)
2016 Peer Avg 2017E Peer Avg 2016 Large Cap
(4)
Oil
www.riceenergy.com
Highly Visible Production and Cash Flow Growth
 Table is set for projected RICE production growth to ~2 Bcfe/d and peer-leading cash flow per share growth
 ~60% volume hedged through 2019E production providing downside protection
VISIBLE GROWTH PROTECTED BY HEDGES
2017E - 2019E CASH FLOW PER SHARE GROWTH
Production (MMcfe/d) and EBITDA(1)($MM)
2,000
1,500
90%
2.0
40%
1.5
30%
1.0
20%
38%
70%
1,000
20%
18%
15%
13%
30%
500
0
2014
2015
(1)
EBITDA
Consensus EBITDA
2016
2017E
2018E
2019E
0.5
–
13% Peer Median
10%
7%
7%
–
RICE
Production
% Hedged
Consensus Production
Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7
'17E - '19E CAGR
__________________________
Note: Peer data and RICE consensus estimates based on Factset as of February 15, 2017. Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN.
1.
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and related reconciliations to comparable GAAP financial measures.
16
Peer Median
www.riceenergy.com
E&P
17
www.riceenergy.com
100% Core E&P Portfolio in Appalachia with Consistent, Attractive Returns
Net Locations and IRRs (1)(2)
PENNSYLVANIA
1,200
1,102
90%
92%
1,000
85%
861
OHIO
800
72%
60%
600
Utica
400
~63,000 net acres
Marcellus
194
200
~185,000 net acres
~105,000 stacked Utica acres
47
0
0%
Marcellus


30%
19%
100% of Appalachian assets in the cores of the Marcellus and Utica
– Added ~100,000 net acres in 2016 for a total leasehold position
of ~248,000 core net acres
Highly concentrated, contiguous position affords longer laterals
– ~10% variability in well performance across leasehold
– Projecting 9,000 foot average laterals spud in 2017

OH Utica Dry OH Utica Wet
Total
Extensive inventory of high returning locations
–
~255 net producing wells, ~1,100+ net locations remaining
–
Potential upside from ~228 PA Utica undeveloped locations
–
Returns improved from 50% in 2016 to ~85% at $3.00 HHUB(2)
–
Average F&D cost of ~$0.50/Mcf
__________________________
1.
Net undeveloped locations as of 12/31/16. See slide entitled “Additional Disclosures” on detail regarding RICE’s methodology for the calculation of locations.
2.
Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice’s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Assumes $3.00
NYMEX; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 17.3 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.
18
www.riceenergy.com
Achieving Shale Scale With 100% Core Appalachia Acreage
Large, concentrated core acreage position in Appalachia

Well Results Heat Map
($ Revenue/Well/Year)
Utica
Core

Marcellus Cores
RICE
100% of RICE inventory in the Appalachian core v. peers
average of only ~60% core inventory
Core Appalachian wells deliver 200% more production than
non-core
Core
Bottom
80th
Percentile
Peer Acreage Map
100%
Rice Energy
85%
80%
80%
60%
Peer Non Core
Acreage
Peer Core Acreage
RICE
Peer 1
Peer 2
Peer 3
Core acreage
Peer 4
45%
45%
Peer 5
Peer 6
Non-core acreage
__________________________
Note: Core outlines based upon state production data and revenue per well ($2.50 dry gas and $45 condensate) and RICE estimates of peer acreage positions based on investor presentations. Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN.
19
35%
Peer 7
www.riceenergy.com
Well Results Driven by Being a Technical Leader
Drilling
Lateral Placement  Pioneered lateral targeting proficiency in the Marcellus
in 2011 using rotary steerable tools
 Every RICE operated well is geosteered by our 24/7
team in RICE’s headquarters
Lateral Length


Completions
Completion Size



Stage Length

Production
Choke
Management

The Future
Innovation Still
in Full Force
Lateral Length (ft.)
10,000


Drilled first 10,000 ft. lateral in 2013
RICE laterals ever since have consistently been on average
2,000-3,000 ft. longer than peers
8,000
6,000
4,000
2,000
Pumped ~1,900 lb/ft. on first Marcellus well (2010)
Pumped ~2,900 lb/ft. on first Utica well (2014)
Most peers’ design just now catching up to what we adopted
8 years ago  “Gen 4” is our “Gen 1”
250 ft. stage length on first Marcellus well  160 ft. stage
length on the 5th well  150-200 ft. stage lengths ever since
In 2010, mapped relationship between flow rate (normalized
for lateral length) and pressures to determine current bestin-class choke management practice
RICE completed ~420 value driving initiatives in 2016 related
to project cost reductions and productivity improvements
We are actively working through >200 new initiatives
20
2010
2,000
2011
2012
2013
2014
2015
2016
Proppant Intensity (lbs/ft.)
Rice Energy
1,000
0
2008
Peers
2009
2010
2011
2012
2013
2014
2015
2016
Stage Length (ft.)
500
400
300
200
Rice Energy
100
0
2010
2011
2012
2013
2014
2015
2016
www.riceenergy.com
Proven, Repeatable Well Design Drives Industry-Leading Results
 RICE’s industry-leading well results are evident in 1-4 year cumulative production per well
 100% of RICE’s expected future Appalachian activity is focused within its concentrated, core acreage position
Cumulative Production per 1,000’ (Mcfe)
SW Appalachia - Marcellus
SW Appalachia - Utica
1,000,000
1,000,000
800,000
800,000
600,000
600,000
400,000
400,000
RICE Utica
RICE Utica
200,000
RICE Marcellus
Industry Marcellus + Utica
200,000
0
RICE Marcellus
0
0
500
1,000
1,500
0
500
1,000
1,500
Days Online
__________________________
Note: Data for RICE based on actuals through 12/31/16, peer data based on Pennsylvania Department of Environmental Protection production reports through 11/30/16 and Ohio Department of Natural Resources report through 9/30/16.
21
www.riceenergy.com
Track Record of Low-Cost Growth
MARCELLUS D&C COSTS ($/FT.)(1)
UTICA D&C COSTS ($/FT.)(1)
$2,590
$1,270
2014
$1,220
2015
$800
$875
2016
2017E
$1,715
2014
NET WELLS TURNED TO SALES AND LATERAL LENGTHS(2)
8,200’
7,300’
44
7
37
2014
9,800’
7,300’
51
9,000’
8,000’
63
25
$1,235
2016
2017E
NET PRODUCTION (MMCFE/D)
80
1,320
27
12
39
2015 PA
9,200’
7,100’
2015
$1,205
36
OH
2016
55
274
2014
2017E
__________________________
1.
2017E well costs assume 10 – 15% service cost increase. Hedged ~60% of 2017E service costs mitigating further cost escalation.
2.
Net wells turned to sales including non-operated Ohio Utica wells and corresponding operated horizontal lateral lengths.
22
552
2015
831
2016
2017E
www.riceenergy.com
Significant Cost Structure Improvements and Still Declining…
Lowest cost structure in the peer group with expected improvement from increased scale
RICE CONSOLIDATED OPERATING COSTS ($/MCFE)
2017E COST STRUCTURE VS. PEERS ($/MCFE)
Cost structure will
continue to decline as
production grows
$1.80
2.5
$2.50
$2.13
$2.00
Cost Structure ($/Mcfe)
$1.35
$0.43
$1.50
$1.12
$0.33
$0.23
$0.57
$0.43
$0.05
$0.39
$0.36
$0.04
$0.41
$0.04
$0.41
1.5
$1.33
$1.12 $1.18
$1.00
1.0
$.50
0.5
$0.32
$0.26
$0.22
$0.17
$0.17
2014
2015
2016
2017E
G&T
$1.72
$0.05
$0.42
LOE
$1.64
2.0
$1.83
Taxes
G&A
2017E Net Production (Bcfe/d)
$1.54
$0.51
$2.20
–
(1)
Interest
RICE Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7
RICE
LOE
G&T
__________________________
Note: Peer data based on Factset as of February 15, 2017. Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN.
1.
2017 estimates based on guidance and interest based on Factset as of February 15, 2017. Consolidated figures eliminate intercompany charge of gathering and compression.
23
Taxes
G&A
Interest
-
Production(Bcfe/d)
www.riceenergy.com
Midstream
24
www.riceenergy.com
RMH - Ohio Gathering: Core Systems with High Growth in the Utica
Legend
Significant RMH EBITDA(1) Growth ($MM)
RICE Acreage
Belmont
OH Gathering
Pipeline
$100
(2)
Strike Force
JV AMI
GPOR
Dedicated to
RICE
RICE
Acreage
Dedicated to
3rd Party
Monroe
PA
OH
WV
$48
 ~162,000 core dedicated acres with ~75% from
high-quality 3rd party customers (GPOR & CNX)
 Systems expected to be monetized into RMP
 75% ownership of Strike Force JV (GPOR 25%)
2016
2017E
__________________________
1.
2.
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and related reconciliations to comparable GAAP financial measures.
Giving effect to Gulfport Midstream’s 25% ownership interests of Strike Force, we expect a range of $95 – 105MM for 2017 Adjusted EBITDA.
25
www.riceenergy.com
RMH - GP Holdings: Rapid Cash Flow Growth



RMH owns 26% of RMP LP units outstanding and 91.75% of IDRs
RMP’s expected 20% distribution growth drives a 5x / 50% CAGR in GP Holdings cash flow in 5 years
One of the only E&P companies in the industry with an unmonetized GP
IDR and LP Distribution Potential ($MM)
$175
$130
$115
$90
$60
$22
$26
$35
$50
$25
$5
$22
$24
$30
$35
$40
2015
2016
2017E
2018E
2019E
LP Distributions
__________________________
Note: Assumes 20% distribution growth and units outstanding remain flat. Net to Rice’s 91.75% interest in GP Holdings.
$80
$50
2020E
$60
2021E
IDR Distributions
26
www.riceenergy.com
RMP: Core System and Execution Drives High Distribution Growth
PA
OH
Significant RMP EBITDA Growth(1) ($MM)
WV
Washington
$193
Belmont
Water
$43
Greene
Gathering
&
Compression
$150
Legend
RICE Acreage
RMP Gathering
Pipeline
RMP Water Pipeline
Beaver
3rd Party Dedicated
to RMP
RMP Water
Interconnects
GPOR Water
Dedication
$158
~215,000 acres dedicated in core of dry gas Marcellus
Primary customers: RICE and EQT
20% distribution growth expected through 2023
100% of cash flow supported by long-term, fee-based contracts
Beginning trunkline buildout in Greene County, PA on Vantage and
western Greene acreage
 2017E budget funded through cash, cash flow and debt
 2nd best performing MLP in the AMZ in 2016(2)
__________________________





1.
2.
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and related reconciliations to comparable GAAP financial measures.
Based on Factset as of February 15, 2017.
27
$64
2015
2016
2017E
www.riceenergy.com
Unparalleled Midstream Growth
RICE has positioned itself as the premier Appalachian core dry gas midstream player
3,000,000
4Q 2016 throughput of ~2,108 MDth/d through RMH and RMP midstream systems
RMP System: 1,203 MDth/d (24% 3rd Party)
RMH System: 904 MDth/d (59% 3rd Party)
2017E Throughput
2,500,000
Dth/d
2,000,000
1,500,000
1,000,000
500,000
–
Jan '14
Jan '15
RMP - Rice Operated (PA)
Jan '16
RMP - 3rd Party (PA)
RMH - 3rd Party (OH)
28
Jan '17
RMH - Rice (OH)
www.riceenergy.com
Significant Unrealized Midstream Value Embedded Within RICE
($ in millions)
IDRs
Estimated Distributions (Avg '17-'19)(1)
Multiple
Esti mated Di stri bu ti ons (Avg '17-'19)
LP Uni ts
Estimated Distributions (Avg '17-'19)(1)
Yield
Esti mated Val u e
25.0x
$675
5.0%
$700
$27
$35
-
35.0x
$950
4.0%
$875
Total GP Hol di ngs
$1,375
-
$1,825
Total Ohi o Mi dstream
$1,100
-
$1,400
$2,475
-
$3,225
Total Potential RMH Value
__________________________
1.
Net to Rice’s 91.75% interest in GP Holdings. Assumes 20% distribution growth.
29
www.riceenergy.com
Financial and Strategic Position
30
www.riceenergy.com
Healthy Balance Sheet Protected by Strong Hedge Book
LOW LEVERAGE(1)


HEDGE SUMMARY
Strong balance sheet across enterprise
Expect to exit 2017 at 1.5x E&P leverage vs. peer average(2)
of >2.4x
1.8x



1,400
1.5x
~90% of 2017E production hedged at $3.17/MMBtu NYMEX
~96% of 2017E production covered by FT or basis hedging
~70% of 2018 (consensus) production(2) hedged at
$3.04/MMBtu NYMEX
$3.17
1,248
1,200
1,000
$3.00
$3.04
$2.87
1.1x
$3.20
1,259
$2.96
$2.87
$2.93
$2.93
631
600
$2.40
510
400
RMH
200
RMP
$1.80
$1.60
2017
Consolidated
YE2016 Net Debt / LTM Adj. EBITDAX
Hedged Volume
2018
2019
NYMEX Avg. Wtd. Floor Price
__________________________
1.
Please see “Non-GAAP Financial Measures” for a description of Adjusted EBITDAX, Further Adjusted EBITDAX, Adjusted EBITDA and related reconciliations to comparable GAAP financial measures.
2.
Based on Factset as of March 20, 2017. Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN.
31
$2.20
$2.00
–
Rice E&P
$2.80
$2.60
800
0.1x
$3.00
2020
Total Avg. Wtd. Floor Price
www.riceenergy.com
Meaningful Takeaway Capacity Expected to Outpace Supply Growth

Expect ~18 Bcf/d incremental takeaway capacity in-service by January 2020 to provide significant
improvement in 2018+ local pricing
– ~10 Bcf/d of expected takeaway received FERC approval or is currently under construction

We don’t expect Appalachia to grow the required 4+ Bcf/d annually to meet FT capacity
Appalachian Basin Production Growth By Rig Count
40
38
Bcf/d
36
34
Supply Scenarios
Strip Pricing Improved Dramatically Since
Vantage Acquisition
2017
2018
2019
2020
M2 Basis Oct. 16 ($1.39) ($0.93) ($0.76) ($0.66)
M2 Basis Feb. 17 ($0.80) ($0.62) ($0.57) ($0.52)
125 Rigs / 38 Bcfd
110 Rigs / 35 Bcfd
32
30
28
26
24
22
85 Rigs / 30 Bcfd
Production Above FT
= Stressed Basis Pricing
65 Rigs / 26 Bcfd
Current
Appalachia
Production
2016
Production below FT = Improved Basis Pricing
2017
2018
2019
2020
60 Rigs-Current Rig Count
50 Rigs / 22 Bcfd
95% Returns at Strip Pricing(1) with Attractive Basis Outlook Risk/Reward
__________________________
1.
Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice’s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Strip pricing as of
February 10, 2017 based on weighted average of undeveloped locations; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 17.3 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.
32
www.riceenergy.com
RICE Trades at a Discount to Peers Despite Most Attractive Attributes



RICE trades at a discount to peers despite core assets, high growth, low leverage & significant midstream value
Financially positioned like a large cap peer, but still growing rapidly
Of the six criteria below, no other company checks half the boxes
9.0x
8.2x
8.0x
Consensus
`18E EV/EBITDA
`17E - `18E
Production
Growth
7.0x
6.3x
35%
5.5x
6.0x
5.0x
4.6x
5.6x
7.2x
7.2x
35%
30%
30%
25%
4.7x
20%
22%
4.0x
3.0x
20%
15%
18%
19%
9%
5%
0.0x
Peer 1
Peer 2
>25% 2018E Production Growth

>245,000 Core Dry Acres


>50% Hedged in 2018


<2.0x YE 2017 Leverage(1)


Retained
Midstream(2)
GP Ownership





15%
10%
2.0x
1.0x
40%
Peer 3






Peer 4






RICE






__________________________
Note: Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN. Based on Factset research and management estimates as of March 20, 2017. Market data as of March 20, 2017.
1.
Leverage represents ratio of net debt to Adjusted EBITDAX. Please see “Non-GAAP Financial Measures” for a description of Adjusted EBITDAX and Further Adjusted EBITDAX.
2.
Retained midstream includes assets owned by the MLP sponsor.
33
0%
Peer 5
Peer 6
Peer 7
















www.riceenergy.com
Attractive Acreage Valuation
 RICE trades at attractive valuation relative to Appalachia peers and Permian operators
 Premium risk-adjusted return profile across RICE’s leasehold given its 100% core, contiguous and fully-delineated
acreage position
–
~85% IRR(1) comparable to core Permian IRRs with lower risk given historical development
$15,000
$11,900
$/Acre
$12,000
$10,700
$9,000
$6,000
$4,500
$3,000
–
RICE
Peer Avg
(2)
Permian Stacked Avg
(3)
__________________________
Note: Based on management analysis.
1.
Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice’s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Assumes $3.00
NYMEX; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 17.3 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.
2.
Peer group includes AR, COG, CNX, EQT, GPOR and RRC. Net acres used in calculation include PA Marcellus and Ohio Utica. GP Values used in calculation are post tax.
3.
Permian stacked average includes FANG, PE and RSPP. Net acres used in calculation are net effective acres.
34
www.riceenergy.com
Top Performing Stock Since IPO
Focused on managing the business for long-term value creation per share
80%
60%
Outperformed 2nd peer by ~37% and median by ~61%
40%
20%
RICE
1%
0%
(20%)
HHUB
(44%)
(40%)
WTI
(49%)
(60%)
Peers
(80%)
(36%) – (82%)
(100%)
Jan '14
__________________________
Note: Peers include AR, CNX, COG, EQT, GPOR, RRC and SWN.
Jan '15
Jan '16
35
Jan '17
www.riceenergy.com
The Premier Appalachian Energy Company
100% of Leasehold in Core of Marcellus and Utica
Differentiated Technical Approach Has Led to Industry Leading Well Results
High Returning Wells Driving Rapid Production Growth
Significant Midstream Value
Strong Balance Sheet and Hedge Position
Nimble and Incentivized Management and Technical Teams
Top-Tier Growth With Attractive Risk-Adjusted Return Profile
36
www.riceenergy.com
Appendix
37
www.riceenergy.com
RICE and RMP Market Snapshot
Rice Energy Inc.
(NYSE: RICE)
Rice Midstream Partners LP
(NYSE: RMP)
($ millions, except per share data)
($ millions, except per unit data)
Management Ownership
Shares Outstanding (MM)
Price
Market Capitalization
Cash
Preferred Equity
~15%
(1)
243
$21.23
$5,150
470
383
Revolving credit facilities
6.25% Senior notes due 2022
7.25% Senior notes due 2023
Enterprise Value
Website:
Investor Contact:
Common Units
Subordinated Units
Total Units Outstanding (MM)
Price
Market Capitalization
Cash
Revolving credit facility
Enterprise Value
243
888
391
$6,585
Distribution/Unit
Yield
Website:
Investor Contact:
www.riceenergy.com
Julie Danvers
[email protected]
73
29
102
$24.58
$2,510
22
190
$2,678
$0.2505
4.08%
www.ricemidstream.com
Julie Danvers
[email protected]
__________________________
Note: Share and unit price as of March 20, 2017. Share count, unit count and balance sheet data as of December 31, 2016. . RICE ownership information taken from public filings and includes ownership of executive officers, directors, Rice trust and other affiliate entities as of March 20, 2017.
1.
Presented as of December 31, 2016 and inclusive of the 40,000,000 Rice Energy Operating LLC common units immediately convertible into 40,000,000 shares of Rice Energy Inc. common stock.
38
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RICE and RMP Organizational Structure
EIG Managed
Funds
$1.45B E&P Borrowing Base
100% Series B
Preferred Equity
($375MM invested)
8.25%
common
equity interest
Rice Midstream
DE
Holdings LLC
91.75% common
equity interest
100% ownership
GP Holdings
(IDRs and LP Interest)
RMP GP
(non-economic)
28% LP interest &
100% of IDRs
$300MM Credit Facility +
$100MM Accordion Feature
100% equity interest
75% equity interest
Rice Olympus
Midstream
(OH Gathering)
Strike Force
Midstream
(GPOR JV)
Rice E&P
ROFO
Assets
$850MM Credit Facility
Public Unitholders
(72% LP Interest)
100% interest
PA Gathering
PA Water
OH Water
__________________________
Ownership percentages as of December 31, 2016.
39
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2017 Detailed Guidance
Net Wells
Operated Marcellus
Operated Ohio Utica
Non-operated Ohio Utica
Total Net Wells
Lateral Length (ft.) of Wells
Operated Marcellus
Operated Ohio Utica
Non-operated Ohio Utica
2017 Capital Budget ($ in millions)
E&P
Operated Marcellus
Operated Ohio Utica
Non-operated Ohio Utica
Total Drilling & Completion
Land
Total E&P
Spud
75
20
10
105
Spud
8,500
10,500
9,500
E&P Guidance
Online
55
20
5
80
Online
8,000
9,000
8,500
$585
$300
$150
$1,035
$225
$1,260
Net Production (MMcfe/d)
Appalachia
Barnett
Total Net Production
% Natural gas
% Operated
% Marcellus
% Utica
Pricing
FT Fuel & Variable (Deduction)
Heat Content (Btu/Scf)
Marcellus
Utica
Operating Costs ($/Mcfe)
Lease Operating Expense
Gathering and Compression
Firm Transportation Expense
Production Taxes and Impact Fees
Total Operating Costs
E&P G&A ($ in millions)
RMH Guidance(1)
2017 Capi tal Budget ($ i n mi l l i ons)
1,205 - 1,265
85 90
1,290 - 1,355
99%
94%
65%
28%
G&A ($ i n mi l l i ons)
Gas Gathering and Compression
Adj usted EBITDA ( 2) ($ i n mi l l i ons)
Gas Gathering and Compression
Operati ng Stati sti cs
$0.11
1,050
1,080
$0.16
$0.45
$0.25
$0.04
$0.90
$85
-
$0.18
$0.47
$0.27
$0.06
$0.98
$90
2.
-
$20
$85
-
$95
1,185
RMP Guidance
2017 Capi tal Budget ($ i n mi l l i ons)
Gas Gathering and Compression
Water Services
Total RMP
Est. Maintenance Capital ($ in millions)
G&A ($ in millions)
Adj usted EBITDA ( 2) ($ i n mi l l i ons)
Gas Gathering and Compression
Water Services
Total Adj u sted EBITDA
% Third Party
Operati ng Stati sti cs
1.
$15
1,125 -
Gathering Throughput (MDth/d)
Distributable Cash Flow(2) ($ in millions)
Average DCF Coverage Ratio(2)
% Distribution Growth
Gathering Throughput (MDth/d)
Water Volumes (MMGal)
__________________________
$315
Gas Gathering and Compression
$255
0$60
$315
$25
$18
$30
$145 - $155
$40 $45
$185
$200
15% - 20%
$160 - $170
1.35x - 1.45x
20%
1,315
1,300
-
1,380
1,450
Does not assume any drop downs. RMH capital budget, G&A and Adjusted EBITDA includes our 75% proportional ownership in Strike Force. Giving effect to Gulfport Midstream’s 25% ownership interests of Strike Force, we expect a range of $95 – 105MM for 2017 Adjusted EBITDA.
Please see "Non-GAAP Financial Measures" for a description of Adjusted EBITDA and Distributable Cash Flow.
40
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2017 D&C Budget Maintains Strong Balance Sheet while Investing in 2018




2017 Budget
2017 budget and guidance:
–
Capex: $1,035MM
–
Production: 1.29 – 1.36 Bcfe/d
Build pads, and drill
and complete wells to
be turned to sales in
2018+
$1,035
$400MM of maintenance to hold
production flat into perpetuity
~$635MM additional capex generates
~80 wells in progress expected to
drive meaningful growth in 2018+
100% core development creates
unique combination of best-in-class
growth while maintaining a strong
balance sheet
2017E Production, MMcfe/d
Drilling and
completing wells that
come online in 2017
Maintenance
drilling and
completion activity
$505
$400
$105
$400
$530
$105
$400
$400
~40% YoY Growth
Flat Exit to Exit
~45% YoY Organic
Growth
~ 45% YoY Organic
Growth
1,145
1,290 – 1,355
1,290 – 1,355
41
$530MM
drives 2018+
production
$505MM
drives 2017
production
www.riceenergy.com
Meaningful Value Derived from Developed Drilling Locations
PROVED RESERVES (BCFE)
Proved Undeveloped
PV-10(1) ($MM)
4,005
1,827
662
644
SEC
2014
$1,019
Proved Developed
Proved Developed
1,306
$3,231
Proved Undeveloped
$1,744
1,700
$600
685
$886
1,015
N.A.
SEC
SEC
SEC
2016
Strip
2014
ACREAGE
$935
$801
SEC
2015
Strip
55,000
56,000
86,000
92,000
2014
2015
__________________________
1.
SEC
2016
Strip
241
851
702
356
215
861
185,000
Marcellus
$1,299
1,102
63,000
148,000
$2,212
NET LOCATIONS
248,000
141,000
$269
$246
$85
2,178
2015
$1,181
$1,568
2016
OH Utica
Please see “PV-10 Reconciliation” for a related reconciliation of PV-10 to the comparable GAAP financial measure.
495
487
2014
2015
Marcellus
42
2016
OH Utica
www.riceenergy.com
Diverse Market Exposure Provides Takeaway Capacity to Multiple Markets
Appalachia takeaway commitments provides access to various markets in North America
TAKEAWAY PORTFOLIO
Canada (MDth/d)
2017E
2018E
42
125
EXPECTED TAKEAWAY CAPACITY (MDTH/D)
Appalachian
Markets
Canadian
Markets
Northeast (MDth/d)
2017E
2018E
96
76
Midwest (MDth/d)
2017E
2018E
107
107
RICE
Acreage
Midwest
Markets
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
TCO (MDth/d)
2017E 2018E
181
95
Gulf Coast
Demand/Exports
by 2020: +12 to
15 Bcf/d(1)
Gulf Coast (MDth/d)
2017E
2018E
Gulf Coast
610
870
–
Jan '15
Jan '16
Jan '17
Jan '18
Jan '19
Jan '20
Illustrative Takeaway Volume Range
Expected Takeaway Capacity
RICE FIRM CAPACITY COMMITMENTS
Pipeline
TETCO
Expected
In-Service Date
In-Service
Volume
(MDth/d)
270
Market
Gulf Coast
REX
In-Service
225
Midwest/Canada/Gulf Coast
CGT/TCO
In-Service
125
TCO, Gulf Coast
Union Town to Gas City
TETCO
In-Service
87
Midwest/Gulf Coast
OPEN
TETCO
In-Service
50
Gulf Coast
Access South
TETCO
17-Nov
320
Gulf Coast
Rover
17-Nov
100
Canada
Project
TEAM South
Rockies Express
Westside Expansion
Markets
Jan '21
ET Rover
Expected Total Capacity
1,177
~65% of expected firm capacity is already in service; remaining 35% expected in service by end of 2017
_______________________
Note: Conversion of Dth to Mcf assumes 1,050 Btu factor.
1.
Source: Company Filings, TPH Estimates.
43
www.riceenergy.com
Basis Exposure & Realized Pricing
PRICING COMMENTARY





FT portfolio covers ~60% of 2017E
takeaway volumes, decreasing to
~40% in 2020E
~96% of 2017E gas is either
transported out of basin or hedged
locally to protect against anticipated
weak 2017E basis
~90% of 2017E production hedged
at $3.17/MMBtu NYMEX
~75% of 2018E gas (based on
consensus production) is either
transported out of basin or hedged
locally
~60%+ in 2020E exposed to local
markets when differentials are
expected to tighten to ~$0.55(1)

Improving FT demand expense
leads to enhanced low-cost margins

Mitigated local basis differential risk
through basis hedges
EXPECTED BASIS EXPOSURE
42%
42%
9%
9%
12%
13%
38%
36%
1Q17E
2Q17E
53%
7%
10%
29%
Gulf Coast
3Q17E
TCO
47%
47%
48%
7%
8%
8%
10%
8%
4%
39%
35%
40%
2017E
2018E
4Q17E
Midwest / Dawn
DTI / M2 / M3
EXPECTED REALIZED PRICING
1Q17E
2Q17E
3Q17E
4Q17E
2017E
2018E
$3.45
(0.26)
(0.12)
0.23
$3.30
(0.29)
$3.19
(0.39)
(0.11)
0.19
$2.88
(0.05)
$3.32
(0.57)
(0.09)
0.17
$2.83
(0.16)
$3.41
(0.36)
(0.11)
0.19
$3.14
(0.22)
$3.34
(0.40)
(0.11)
0.19
$3.02
(0.18)
$3.09
(0.29)
(0.09)
0.18
$2.89
(0.08)
Post Hedged Realized Price ($/Mcf)
FT Demand Expense
$3.01
($0.28)
$2.83
($0.26)
$2.67
($0.21)
$2.92
($0.27)
$2.84
($0.26)
$2.81
($0.29)
FT Expense (Fuel & Variables + Demand)
FT Expense + Basis + BTU Uplift
($0.40)
($0.43)
($0.37)
($0.57)
($0.31)
($0.70)
($0.38)
($0.55)
($0.37)
($0.58)
($0.38)
($0.49)
NYMEX Henry Hub Strip ($/MMBtu)(1)
Plus/Less: Average Basis Impact
Less: Firm Transportation Fuel & Variables
Plus: BTU Uplift (MMBtu/Mcf)
Pre-Hedge Realized Price ($/Mcf)
Plus: Realized Hedging Gain/Loss ($/Mcf)
_______________________
1.
Strip pricing as of February 10, 2017.
44
www.riceenergy.com
Firm Transportation and Basis Exposure
Cost of firm transportation must be factored into realized pricing comparisons across Appalachian peers
2018 strip basis has tightened $0.30 since October 2016, highlighting the value of RICE’s balanced FT portfolio


2017
2018
Appalachian Basis Assumption = ($0.80) Strip
$1.00
$0.80
$1.00
$0.80
Appalachian Basis Assumption = ($0.50)
App Basis Strip ($0.62)
$0.10
$0.69
$0.71
$0.62
$0.64
$0.43
$0.50
$0.80
RICE
$0.80
$0.50
$0.34
–
No FT
–
Full FT
RICE
Firm Transportation Expense
(Demand + Fuel & Variables)
$0.57
$0.34
$0.50
$0.37
–
$0.50
$0.29
$0.70
$0.60

Appalachian Basis Assumption = ($0.50)
App Basis Strip ($0.57)
$0.90
$0.10
$0.63
$0.50
Full FT
$1.00
$0.80
$0.70
$0.10
2019
$0.30
–
–
No FT
Full FT
RICE
–
No FT
Wtd Average Basis
Chart illustrates all-in FT + Basis expense (pre-hedge) for
1)
Producer with 100% of volumes covered under firm transportation (“Full FT”)
2)
RICE
3)
Producer with no FT that is 100% exposed to local Appalachian prices (“No FT”)

Full FT has a low all-in expense in 2017 while Appalachian basis differentials are weak, but as new and expensive FT projects come
online in 2018/2019, Appalachian basis will strengthen lowering RICE’s cost structure

For those completely covered by FT (or long FT), their relative cost structure will be fixed at higher levels than peers
_______________________
Note: Based on management estimates. Strip pricing as of February 10, 2017.
45
www.riceenergy.com
Attractive Single Well Economics


RICE continues to drive down D&C and operating costs to maximize returns
Inventory currently generates ~95% returns at strip; HHUB PV-10 breakevens of ~$1.75 HHUB(1)
DRY GAS SINGLE WELL ECONOMICS
206%
142%
92%
53%
166%
115%
72%
39%
$2.50
$3.00
Net Locations (2)
HHUB PV-10 Breakeven ($/MMBtu)
$3.50
NYMEX ($/MMBtu)
MARCELLUS
UTICA
861
194
$1.67
$1.90
$4.00
__________________________
Note: Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice’s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Assumes long-term
well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 17.3 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.
1.
Strip pricing as of February 10, 2017.
2.
Excludes ~47 wet OH Utica net undeveloped locations and ~228 dry gas PA Utica net undeveloped locations.
46
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Marcellus and Utica Single Well Type Curves
MARCELLUS SINGLE WELL TYPE CURVE
14
4.5
EUR (Bcf/1,000')
Lateral Length
EUR (Bcf)
Interwell Spacing
Choke (MMcf/d per 1,000')
Flat Time (Days)
1-year Cum. (Bcf)
2-year Cum. (Bcf)
5-year Cum. (Bcf)
10-year Cum. (Bcf)
IRR ($3.00 HHub)
PV-10 ($MM) ($3.00 HHub)
Marcellus
2.16
8,000
17.3
750
1.5
180
3.8
5.9
9.2
12.2
92%
$9.6
4.5
EUR (Bcf/1,000')
Lateral Length
EUR (Bcf)
Interwell Spacing
Choke (MMcf/d per 1,000')
Flat Time (Days)
1-year Cum. (Bcf)
2-year Cum. (Bcf)
5-year Cum. (Bcf)
10-year Cum. (Bcf)
IRR ($3.00 HHub)
PV-10 ($MM) ($3.00 HHub)
OH Utica
2.33
9,000
21.0
1,000
1.8
365
5.8
9.0
12.5
15.2
72%
$9.9
Restricted Rate
12
MMcf/d
10
8
6
4
2
–
–
0.5
1.0
1.5
2.0
Years
2.5
3.0
3.5
4.0
OHIO UTICA SINGLE WELL TYPE CURVE
20
Restricted Rate
MMcf/d
15
10
5
–
–
0.5
1.0
1.5
__________________________
Note: See appendix for summary of assumptions used to generate single well IRRs.
2.0
Years
2.5
3.0
47
3.5
4.0
www.riceenergy.com
Economic Assumptions: Improved Cost Structure and Lateral Lengths
Feb `16
Feb `17
% Change
Net Locations
487 Marcellus / 215 Utica
702 Total
861 Marcellus / 241 Utica
1,102 Total
↑57%
Lateral Length
7,000 Marcellus
9,000 Utica
8,000 Marcellus
9,000 Utica
↑14%
-%
Net Horizontal
Feet (MM ft)
2.8 Marcellus / 1.5 Utica
4.3 Total
5.7 Marcellus / 1.7 Utica
7.5 Total
↑74%
D&C Costs
($/lateral ft)
$1,150 Marcellus
$1,450 Utica
$875 Marcellus
$1,235 Utica
↓24%
↓15%
$1.14
$0.94
↓18%
Single Well
IRRs(2)
~49% Marcellus
~47% Utica Dry
~90% Marcellus
~70% Utica
↑88%
↑53%
Single Well
PV-10(2)(3)
$7.6MM Marcellus
$8.2MM Utica Dry
$9.6MM Marcellus
$9.9MM Utica
↑26%
↑21%
Operating
Costs ($/Mcfe)(1)
__________________________
1.
Operating costs include lease operating, gathering and compression, firm transportation and production taxes.
2.
Marcellus and Utica economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (Rice’s direct subsidiary, REO, owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs). Assumes $3.00
NYMEX; estimated well costs of $875 per lateral foot and $1,235 per lateral foot in the Marcellus and Utica, respectively. Assumes EURs of 17.3 Bcf and 21.0 Bcf in the Marcellus and Utica, respectively.
3.
Please see “PV-10 Reconciliation” for a related reconciliation of PV-10 to the comparable GAAP financial measure.
48
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Economics
PV10 & IRRS(1)(3)
ECONOMIC ASSUMPTIONS
Marcellus
Economics Adjusted for Gathering Ownership at $3.00 HHUB & $27/bbl NGLs
100%
Type Well Assumptions
Spacing
Lateral Length
GAS EUR (Bcf/1,000')
Condensate EUR (Bcf/1,000')
NGL Yield (bbls/mmcf)
Gas Shrink
Pre-Processed EUR (Bcfe)
Post-Processed EUR (Bcfe)
% Gas
Heat Content (Btu/Scf)
Initial Choke (MMcf/d per 1,000')
Flat Period (days)
$12.0
92%
90%
$9.9
$10.0
80%
$9.6
72%
70%
60%
50%
$6.0
Operating Expenses (NRI Gas)
Fixed Operating Expenses ($/well/month)
Variable Operating Expenses ($/mcf)
All-in Operating Expenses ($/mcf)
PV10 ($mm)
IRR
Utica Wet
750
8,000
2.16
–
–
–
17.3
17.3
100%
1,050
1.61
180
1,000
9,000
2.33
–
–
–
21.0
21.0
100%
1,080
1.80
180
1,000
9,000
1.83
0.07
26
13%
16.5
17.5
82%
1,175
1.41
180
$7.0
$875
$11.1
$1,235
$11.1
$1,235
$6,378
$0.11
$0.17
$6,378
$0.11
$0.16
$6,378
$0.11
$0.17
(2)
D&C Assumptions (2)
D&C ($mm)
D&C per Lateral ($ per foot)
$8.0
Other Costs/Expenses (NRI Gas)
Well Impact Fee?
Severance Taxes ($/mcf)
Avg. Royalty
40%
$4.0
30%
$2.3
20%
19%
0%
OH Utica Dry
IRR
No
$0.04
20%
$0.45
–
$0.46
–
$1.01
$5.08
Adjusted Gathering and Compression Fees ($/dth)
Midstream Adjustment
$0.22
50%
$0.23
50%
$1.01
–
(13% )
($0.23)
($0.63)
861
5.7
194
1.4
47
0.3
Economics Summary (Adjusted for Ownership of Midstream In Each Area, $3.00 HHUB, $27/bbl NGLs)
PV-10 Single Well
$9.6
$9.9
IRR
92%
72%
Payback (Months)
25
26
Breakeven Realized ($/dth)
$1.67
$1.90
OH Utica Wet
PV10
__________________________
1.
Economics assume E&P is burdened by 50% of the gathering and compression fee and 50% of water completion fees (RICE owns a 26% LP interest in RMP, 100% of Rice Olympus Midstream and 91.75% of RMP IDRs).
2.
D&C costs are fully burdened by water completion fees of ~$50 per lateral foot in the Marcellus and ~$65 per lateral foot in the Utica.
Please see “PV-10 Reconciliation” for a related reconciliation of PV-10 to the comparable GAAP financial measure.
No
$0.04
20%
Gathering, Processing and Compression (NRI Gas)
Gathering, Compression, Processing Fees ($/dth)
NGL Fractionation and Transport ($/bbl)
Inventory
Net Undeveloped Locations
NRI Undeveloped Horizontal Feet (mm ft)
–
Marcellus
Yes
–
17%
Firm Transportation and Basis (NRI Gas)
Basis + Fuel (Variable) % of Gas Price
Wtd. Avg Reservation Fee + Commodity Fee (Fixed) $/dth
All-In Assuming $3.00 HHUB (NRI)
$2.0
10%
3.
Utica Dry
49
$2.3
19%
56
$2.65
www.riceenergy.com
Hedging Summary
 RICE’s gas will be marketed into 4 areas
– (1) Gulf Coast (ELA, M1)
– (2) TCO
– (3) Midwest (Chicago, Dawn)
– (4) Appalachia (M2, M3, &
Dominion)
 ~60% of expected first quarter 2017
production transported out of
Appalachian basin
 Our Gulf Coast firm transportation
contracts deliver to markets in the Gulf
Coast (ELA, M1, Etc.)
– We hedge our Gulf Coast basis
exposure opportunistically, but
believe our Henry Hub NYMEX
derivatives serve as a hedge
against these indices which have
historically traded within a narrow
band of $0.05-$0.15 below Henry
Hub
1Q17E
2Q17E
3Q17E
4Q17E
2017E
2018E
2019E
2020E
2021E
Hedged M2 / Dominion Volumes (BBtu/d)
Wtd Avg Floor Price ($/MMBtu)
% of Bas is Hedged
470
$2.39
n.a.
560
$2.13
n.a.
715
$2.00
n.a.
667
$2.19
n.a.
604
$2.16
93%
567
$2.30
n.a.
535
$2.36
n.a.
475
$2.37
n.a.
300
$2.32
n.a.
Hedged TCO Volumes (BBtu/d)
Wtd Avg Floor Price ($/MMBtu)
% of Bas is Hedged
168
$3.03
n.a.
143
$2.97
n.a.
138
$2.92
n.a.
63
$2.90
n.a.
128
$2.95
92%
39
$2.72
n.a.
10
$2.58
n.a.
–
–
n.a.
–
–
n.a.
Hedged Gulf Coas t Volumes (BBtu/d)
Wtd Avg Floor Price ($/MMBtu)
% of Bas is Hedged
376
$3.11
n.a.
187
$3.07
n.a.
303
$3.02
n.a.
594
$3.04
n.a.
366
$3.06
68%
598
$2.93
n.a.
108
$2.85
n.a.
42
$2.78
n.a.
–
–
n.a.
Hedged Chicago/Dawn Volumes (BBtu/d)
Wtd Avg Floor Price ($/MMBtu)
% of Bas is Hedged
129
$3.21
n.a.
188
$3.05
n.a.
188
$3.00
n.a.
100
$3.04
n.a.
151
$3.06
100%
56
$2.89
n.a.
39
$2.82
n.a.
32
$2.81
n.a.
20
$2.73
n.a.
Total Hedged Volumes (BBtu/d) (1)
Wtd Avg Floor Price ($/MMBtu) (2)
HHUB S wap, Collar & Put Floor ($/MMBtu) (3)
% Hedged (4)
_______________________
1.
Hedges shown prior to bid-week trades.
2.
Includes the effect of basis hedges.
3.
Wtd. avg. fixed price floor.
4.
Assumes the mid-point of guidance.
50
1,144
1,077
1,343
1,424
1,248
1,259
692
548
320
$2.81
$3.23
n.a.
$2.56
$3.18
n.a.
$2.47
$3.13
n.a.
$2.63
$3.14
n.a.
$2.61
$3.17
90%
$2.64
$3.04
n.a.
$2.46
$2.96
n.a.
$2.43
$2.93
n.a.
$2.34
$2.85
n.a.
www.riceenergy.com
Hedging Detail
All-In Fixed Price Derivatives
1Q17E
2Q17E
3Q17E
4Q17E
2017E
2018E
2019E
2020E
2021E
Bas is Contract Derivatives
NYMEX Natural Gas S waps
Volume Hedged (BBtu/d)
Wtd. Avg. S wap Price ($/MMbtu)
529
$3.37
489
$3.30
718
$3.21
769
$3.22
627
$3.26
665
$3.00
340
$2.94
510
$2.93
160
$2.85
Appalachian Bas is
Volume Hedged (BBtu/d)
Wtd. Avg. S wap Price ($/MMbtu)
270
($0.80)
353
($1.10)
495
($1.20)
NYMEX Natural Gas Collars
Volume Hedged (BBtu/d)
Wtd. Avg. Call Price ($/MMbtu)
Wtd. Avg. Floor Price ($/MMbtu)
290
$3.73
$3.08
290
$3.73
$3.08
290
$3.73
$3.08
290
$3.73
$3.08
290
$3.73
$3.08
285
$3.63
$3.15
170
$3.52
$3.00
–
–
–
–
–
–
Other Bas is
Volume Hedged (BBtu/d)
Wtd. Avg. S wap Price ($/MMbtu)
635
($0.11)
492
($0.13)
Total Bas is Hedges (Financial + Phys ical)
Volume Hedged (BBtu/d)
Wtd. Avg. S wap Price ($/MMbtu)
904
($0.32)
845
($0.54)
NYMEX Natural Gas Calls
Volume Hedged (BBtu/d)
Wtd. Avg. Call Price ($/MMbtu)
NYMEX Natural Gas Deferred Puts
Volume Hedged (BBtu/d)
Wtd. Avg. Net Floor Price ($/MMbtu)
60
$3.50
40
$2.50
60
$3.50
40
$2.50
60
$3.50
70
$2.51
60
$3.50
70
$2.51
60
$3.50
55
$2.50
120
$3.32
30
$2.77
110
$3.55
20
$2.80
135
$3.47
–
–
–
–
–
–
Total NYMEX Index Derivatives
NYMEX Volume Hedged (BBtu/d)
NYMEX Volume Hedged Incl. Calls (BBtu/d)
S wap, Collar & Put Floor ($/MMbtu)
859
919
$3.23
819
879
$3.18
1,078
1,138
$3.13
1,129
1,189
$3.14
972
1,032
$3.17
980
1,100
$3.04
530
640
$2.96
510
645
$2.93
160
160
$2.85
WAHA Natural Gas S waps
Volume Hedged (BBtu/d)
Wtd. Avg. S wap Price ($/MMbtu)
85
$3.06
52
$3.07
45
$3.03
45
$3.11
57
$3.07
22
$3.01
9
$3.29
–
–
–
–
Dominion Natural Gas S waps
Volume Hedged (BBtu/d)
Wtd. Avg. S wap Price ($/MMbtu)
200
$2.33
207
$2.22
220
$2.17
250
$2.24
219
$2.24
257
$2.23
92
$2.34
–
–
–
–
Total Index Derivatives
(1)
Total Fixed Volume Hedged (BBtu/d)
1,144
(1)
Total Fixed Volume Hedged Incl. Calls (BBtu/d) 1,204
S wap, Collar & Put Floor ($/MMbtu)
$3.06
1,077
1,137
$2.99
1,343
1,403
$2.97
1,424
1,484
$2.98
1,248
1,308
$3.00
1,259
1,379
$2.87
631
741
$2.87
510
645
$2.93
160
160
$2.85
_______________________
1.
Hedges shown prior to bid-week trades.
51
1Q17E
2Q17E
3Q17E
4Q17E
2017E
2018E
2019E
2020E
2021E
417
($0.99)
385
($1.05)
310
($0.67)
442
($0.59)
475
($0.56)
300
($0.53)
485
($0.13)
392
($0.12)
500
($0.12)
280
($0.14)
167
($0.15)
73
($0.14)
20
($0.12)
980
($0.67)
810
($0.57)
885
($0.53)
589
($0.42)
610
($0.47)
548
($0.51)
320
($0.50)
WTI S waps
Volume Hedged (Bbl/d)
Wtd. Avg. S wap Price ($/Bbl)
50
$45
50
$45
50
$45
50
$45
50
$45
–
–
–
–
–
–
–
–
NGL S waps
Volume Hedged (Bbl/d)
Wtd. Avg. S wap Price ($/Bbl)
507
$15
501
$15
496
$15
496
$15
500
$15
–
–
–
–
–
–
–
–
www.riceenergy.com
Fourth Quarter 2016 RICE Highlights
1,145
4Q16 production (MMcfe/d)
49%
YoY organic
production increase
1.5x
Consolidated Leverage(1)
Solid Fourth Quarter Results

Net loss of $205MM, a 50% increase over 4Q15

Adjusted EBITDAX(1) of $202MM, a 53% increase over 4Q15

D&C well costs in the Marcellus and Utica to $775 and $1,100 per lateral foot, respectively, for wells
drilled and completed in 4Q16

Average NYMEX differential of ($0.56)/MMBtu with 67% of production priced outside Appalachia
Prolific Retained Midstream Growth

Achieved record quarterly RMH gathering throughput of 904 MDth/d, a 180% increase over 4Q15

Increased total core acreage dedication to ~162,000 in Belmont and Monroe Counties, OH
Strong Liquidity and Healthy Balance Sheet

Increased borrowing base to $1.45B from $1B in Dec. 2016 to incorporate the Vantage assets

Strong 4Q16 liquidity position of $1.9B(2) to fund 2017 E&P and RMH capital needs
2017 Detailed Guidance

D&C budget of $1,035MM driving projected ~45% organic (~60% reported) YoY production growth

Majority of RMH budget of $315MM allocated to building out trunklines of Strike Force JV and
installing compression in Ohio
__________________________
1.
Please see “Non-GAAP Financial Measures” for a description of Adjusted EBITDAX, Further Adjusted EBITDAX and related reconciliations to comparable GAAP financial measures.
2.
Excludes Rice Midstream Partners LP.
52
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Fourth Quarter & Full-Year 2016 Operational Highlights
MARCELLUS OPERATIONAL HIGHLIGHTS

Turned to sales 18 gross (18 net) Marcellus wells in 4Q16
–



Avg. lateral length of ~6,700 feet

Drilled 7 net wells and completed 9 net wells
In 2016, turned to sales 36 gross (36 net) Marcellus wells
with an average lateral length of ~7,100 feet

Drilled 9 net wells and completed 9 net wells
In 2016, turned to sales 20 gross (13 net) operated Utica
wells with an average lateral length of ~9,300 feet
–
Expect 2017 well costs to average ~$875 per lateral foot
18
4Q16 Utica development costs averaged $1,100 per
lateral ft.
–
4Q16 Marcellus development costs averaged $775 per
lateral ft.
–

UTICA OPERATIONAL HIGHLIGHTS
Turned to sales 38 gross (14 net) non-operated Utica
wells
Expect 2017 well costs to average ~$1,235 per lateral foot
18
18
2
9
9
18
9
7
Net Wells Drilled
Operated Marcellus
Net Wells Completed
Operated Ohio Utica
Net Wells Turned to Sales
Non-Operated Ohio Utica
Strong Execution Drives Leading Edge D&C Costs and Well Results
53
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RICE Fourth Quarter 2016 Consolidated Financial Summary
Solid fourth quarter results supported by well-capitalized balance sheet and ample liquidity
CAPITALIZATION
QUARTERLY HIGHLIGHTS
 4Q16 production of 1,145 MMcfe/d, 49% organic increase from 4Q15
 67% of 4Q16 production sold to premium, non-Appalachian markets
 Increased borrowing base to $1.45B in December
Appalachia
Barnett
Total net production (MMcfe/d)
% Gas
% Operated
% Marcellus
% Utica
Three Months Ended
December 31, 2016
1,072
73
1,145
99 %
88 %
61 %
32 %
Actual ($MM)
NYMEX Henry Hub price ($/MMBtu)
Average basis impact ($/MMBtu)
Firm transportation fuel & variables ($/MMBtu)
Btu uplift (MMBtu/Mcf)
Pre-hedge realized price ($/Mcf)
Realized hedging gain ($/Mcf)
Post-hedge realized price ($/Mcf)
Lease operating
Gathering, compression and transportation
Production taxes and impact fees
General and administrative
Depletion, depreciation and amortization
Net (loss)
Adjusted EBITDAX (1)
Further Adjusted EBITDAX (1)
($ in millions)
Cash
Rice Energy
Rice Midstream Holdings
Rice Midstream Partners
Total cash and cash equivalents
$18
$39
$6
$29
$121
Mezzanine equity
Long-term debt
Rice Energy
E&P credit facility
6.25% Senior notes due 2022(2)
7.25% Senior notes due 2023(2)
Total Rice Energy long-term debt
Rice Midstream Holdings credit facility
Rice Midstream Partners credit facility
Total consolidated long-term debt
Net debt
$/Mcfe
$2.98
($0.56)
($0.12)
$0.12
$2.42
$0.33
$2.75
$0.18
$0.37
$0.06
$0.32
$1.15
($204)
$202
$239
$399
$49
$22
$470
$383
–
$888
$391
$1,279
$53
$190
$1,522
$1,052
Leverage
Rice Energy E&P
Rice Midstream Holdings(3)
(3)
Rice Midstream Partners
(1)
Consolidated
1.8x
0.1x
1.1x
1.5x
Capex Incurred (Excluding Acquisitions)
D&C
(4)
Land
RMH
RMP
$163
$38
$33
$22
__________________________
1.
Please see “Non-GAAP Financial Measures” for a description of Adjusted EBITDAX, Further Adjusted EBITDAX and related reconciliations to comparable GAAP financial measures.
2.
2022 and 2023 Senior notes, net of unamortized deferred finance costs of $12MM and $8MM, respectively.
3.
Please see “Adjusted EBITDA and DCF Reconciliation” for reconciliations to comparable GAAP financial measures.
4.
Land capex reflects cash spend.
54
Three Months Ended
December 31, 2016
www.riceenergy.com
Water Business – Complementary to Core Gathering & Compression Business
1. Source freshwater
from rivers and other
local sources in
Pennsylvania & Ohio
3. Provide freshwater
services to pads for
completion activity
2. Pump freshwater
through permanent
and temporary
pipelines from
sources to pads
(fee charged based on
volume delivered)
4. Recycle produced
water onsite and/or
coordinate disposal
via trucks
(fee charged based on
% of cost)
 Provides a faster, more efficient and reliable method of water transportation versus trucking
– Reduced emissions, noise, road repairs and safety incidents
 Highly accretive to RMP
 Enables RICE E&P to complete a greater number of stages per day versus trucking
55
www.riceenergy.com
Integrated Water Services Business

Providing fresh water to support Marcellus and Utica
completion operations
WATER SERVICES AGREEMENTS OVERVIEW
Assumptions
Water services business is complementary to gas
gathering and compression services and has strong cash
operating margins of ~75%

Provides a faster, more efficient and reliable method of
water transportation versus trucking
19
Weighted Average Fee(1)
$0.056
$0.059
Operating Expense
$0.022
$0.016
Cash Flow per Well
$442,000
$817,000
500
– Reduced emissions, noise, road repairs and safety
incidents
463
18
400
MMgal

Volumetric fee structure is tiered to provide revenue and
cash flow stability
– RMP also collects, recycles or disposes of flowback
and produced water and charges 2% of cost
300
335
269
154
176
66
0
1Q16
__________________________
1.
Affiliate and third party weighted average based on 15% total third party water volumes.
56
321
115
200
100
– Water service fee charged based on volume
delivered to pad
Ohio
13
Fresh Water Usage (MMGal/well)(1)
– Access to >36 MMgal/d of fresh water in PA and OH

Pennsylvania
2Q16
PA
OH
172
135
135
3Q16
3rd Party
149
4Q16
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Additional Disclosures
Determination of Identified Drilling Locations as of December 31, 2016:
Net undeveloped locations are calculated by taking our total net acreage, subtracting producing acreage, and
multiplying such amount by a risking factor. Remaining risked acreage is then divided by our expected well
spacing. Producing acreage is calculated with the same methodology based on actual lateral lengths and interwell spacing.
Undeveloped Net Marcellus Locations – RICE assumes these locations have 8,000 foot laterals and 750 foot spacing
between wells which yields approximately 138 acre spacing. In the Marcellus, RICE applies a 20% risking factor to
its net acreage to account for inefficient unitization and the risk associated with its inability to force pool in
Pennsylvania. As of December 31, 2016, RICE had approximately 185,000 net acres in the Marcellus which results
in 861 undeveloped net locations.
Undeveloped Net Ohio Utica Locations – RICE assumes these locations have 9,000 foot laterals and 1,000 foot
spacing between wells which yields approximately 207 acre spacing. In the Ohio Utica, RICE applies a 10%
risking factor to its net acreage to account for inefficient unitization. As of December 31, 2016, RICE had
approximately 63,000 net acres prospective for the Utica in Ohio which results in 241 undeveloped net locations.
Undeveloped Net Pennsylvania Utica Locations – RICE assumes these locations have 8,000 foot laterals and 2,000
foot spacing between wells which yields approximately 367 acre spacing. In the Pennsylvania Utica, RICE applies
a 20% risking factor to its net acreage to account for inefficient unitization. As of December 31, 2016, RICE had
approximately 105,000 net acres prospective for the Utica in Pennsylvania which results in 228 undeveloped net
locations.
57
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