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Rice Energy Reports Fourth Quarter and Full-Year 2016 Financial and Operating Results

CANONSBURG, Pa., Feb. 22, 2017 /PRNewswire/ -- Rice Energy Inc. (RICE) ("Rice Energy") today reported fourth quarter and full-year 2016 financial and operational results. 2016 highlights include:

  • Fourth quarter net production averaged 1,145 MMcfe/d, an 83% increase from prior year's quarter (49% increase excluding acquired Vantage Energy production)
  • 2016 net production averaged 831 MMcfe/d, 4% above the high end of guidance and a 51% increase from prior year (41% increase excluding acquired Vantage Energy production)
  • Invested $686 million of E&P capital in 2016 with development costs per foot approximately 32% below the 2015 average
  • Reduced fourth quarter per unit operating costs to $0.61 per Mcfe, a 14% decrease from the prior year quarter
  • Net loss of $204.5 million for the fourth quarter and $248.8 million for the full year
  • Adjusted EBITDAX(1) of $202 million for the fourth quarter and $575.5 million for the full year
  • Year-end 2016 proved reserves totaled 4.0 Tcfe, a 136% increase, with $1.6 billion and $3.2 billion pre-tax PV-10(1) at SEC and strip pricing(2), respectively
  • Added approximately 100,000 net acres in Appalachia throughout the year and ended the year with approximately 248,000 net Appalachian acres
  • Rice Midstream Holdings LLC ("RMH") 2016 gathering throughput of 708 MDth/d, an increase of 187% relative to the prior year
  • Acquired Vantage Energy for $2.7 billion on October 19, 2016
  • Exited the year with liquidity of $1.9 billion(3) and leverage of 1.5x(1) net debt to 2016 Further Adjusted EBITDAX

Commenting on the results, Daniel J. Rice IV, Chief Executive Officer, said, "We faced the challenging 2016 business headwinds head on and used them as an opportunity to demonstrate the resiliency of our assets, our strategy and our team. We meaningfully reduced our development and operating costs without compromising the productivity of our core wells, which made us a leaner, more efficient organization, which in turn made our acquisition of Vantage Energy that much more attractive. The Vantage Energy acquisition checks all of our strategic boxes and allows us to operate at a greater scale with one of the largest, most concentrated drilling inventories of truly core acreage in the Appalachia basin. I am proud of our record results in 2016 that have provided the operational momentum to repeat our success in 2017."

1.

Please see "Supplemental Non-GAAP Financial Measures" for a description of Adjusted EBITDAX, Further Adjusted EBITDAX, PV-10 and related reconciliations to comparable GAAP financial measures.

2.

Strip pricing as of 12/31/16.

3.

Excludes Rice Midstream Partners LP.

 

2016 Consolidated Results


Three Months Ended December 31, 2016


Year Ended December 31, 2016






Net Production (Bcfe)




Appalachia

98.7



297.7


Barnett

6.7



6.7


Total Net Production

105.4



304.4


% Gas


99

%


99

%

  % Operated


88

%


88

%

  % Marcellus


61

%


65

%

  % Utica


32

%


32

%






NYMEX Henry Hub price ($/MMBtu)


$

2.98



$

2.46


Average basis impact ($/MMBtu)


(0.56)



(0.28)


FT fuel and variables ($/MMBtu)


(0.12)



(0.14)


Btu uplift (MMBtu/Mcf)


0.12



0.10


Pre-hedge realized price ($/Mcf)


2.42



2.14


Realized hedging gain ($/Mcf)


0.33



0.67


Post-hedge realized price ($/Mcf)


2.75



2.81


Capacity optimization ($/Mcf)




0.01


Adjusted realized price ($/Mcf)


$

2.75



$

2.82







Operating revenues (in thousands)


$

284,046



$

778,906


Realized gain on derivative instruments (in thousands)


34,720



201,071


Total operating revenues and realized gain on derivative instruments (in thousands)


$

318,766



$

979,977







Average costs per Mcfe:





Lease operating expense(1)


$

0.18



$

0.17


  Gathering, compression and transportation expense


$

0.37



$

0.41


Production taxes and impact fees


$

0.06



$

0.05


General and administrative expense(1)


$

0.32



$

0.39


Depreciation, depletion and amortization


$

1.15



$

1.21







Net loss (in thousands)


$

(204,493)



$

(248,820)


Adjusted EBITDAX (in thousands)(2)


$

202,027



$

575,547







Total RMH throughput (MDth/d)


904



708


% Third-party


59

%


62

%



1.

Excludes non-cash equity compensation expense of $0.01 million and $4.9 million attributable to lease operating and general and administrative expenses, respectively, for the three months ended December 31, 2016 and $0.6 million and $21.3 million attributable to lease operating and general and administrative expenses, respectively, for the year ended December 31, 2016.

2.

Please see "Supplemental Non-GAAP Financial Measures" for a description of Adjusted EBITDAX and the reconciliation to net income (loss), the comparable GAAP financial measure.



Fourth Quarter 2016 Financial Results

We reported a net loss attributable to our common stockholders of $178.4 million or ($0.88) per diluted share for the fourth quarter 2016, a 36% increase over the prior year quarter. Adjusted EBITDAX(1) for the quarter was $202 million, a 53% increase over the prior year quarter. We reported adjusted net income(1) of $75.6 million, or $0.37 per diluted share, after excluding non-recurring income and expense items.

Net production totaled 105.4 Bcfe, or an average of 1,145 MMcfe/d, representing an 83% increase above the prior year quarter. Excluding production attributable to the Vantage Energy acquisition, fourth quarter net production was 49% higher than the prior year quarter. Total operating revenues and realized gain on derivative instruments were $319 million.

For the three months ended December 31, 2016, our average realized natural gas price was $2.42 per Mcf, excluding hedges and $2.75 per Mcf including hedges. Approximately 67% of our fourth quarter production received favorable Gulf Coast, TCO and Midwest pricing. Our average basis differential for the quarter was ($0.56) per MMBtu, while TETCO M2 and Dominion South averaged ($1.53) and ($1.52) per MMBtu, respectively, below NYMEX Henry Hub for the quarter.

The sum of our lease operating expense; gathering, compression and transportation expense; and production taxes and impact fees on a per unit basis were $0.61 per Mcfe, a 14% decrease from the prior year quarter. This decrease was driven by a 27% per unit decrease in gathering, compression and transportation expense, partially offset by modest increases in lease operating expense and production taxes and impact fees attributable to the legacy Vantage Energy Barnett assets.

During the fourth quarter, we invested $201 million in our E&P operations (excluding the Vantage Energy acquisition), consisting of $159 million to drill and complete operated Marcellus and Ohio Utica wells, $4 million for non-operated Ohio Utica development and $38 million for land. In addition, we invested $33 million in our RMH midstream assets to construct our Ohio gas gathering systems.

1.

Please see "Supplemental Non-GAAP Financial Measures" for a description of Adjusted EBITDAX and adjusted net income (loss) and the related reconciliations thereof to net income (loss), the comparable GAAP financial measures.



Full-Year 2016 Financial Results

We reported a net loss attributable to our common stockholders of $298.2 million or ($1.84) per diluted share for 2016, a 2% decrease over the prior year. Adjusted EBITDAX(1) during 2016 was $575.5 million, a 33% increase over the prior year. We reported adjusted net income(1) of $59.5 million, or $0.37 per diluted share.

Net production totaled 304.4 Bcfe, or an average of 831 MMcfe/d, representing a 51% increase over the prior year and 4% above the high end of guidance. Excluding production attributable to the Vantage Energy acquisition, 2016 net production was 41% higher than the prior year. Total operating revenues and realized gain on derivative instruments were $980 million.

For the year ended December 31, 2016, our average realized natural gas price was $2.14 per Mcf, excluding hedges and $2.81 per Mcf including hedges. Approximately 79% of our 2016 production received favorable Gulf Coast, TCO and Midwest pricing. Our average basis differential for the year was ($0.28) per MMBtu, while TETCO M2 and Dominion South averaged ($1.11) and ($1.09) per MMBtu, respectively, below NYMEX Henry Hub for the year.

The sum of our lease operating expense; gathering, compression and transportation expense; and production taxes and impact fees on a per unit basis were $0.63 per Mcfe, a 7% decrease from the prior year due to a reduction in rental expenses and water disposal costs within lease operating expense.

During 2016, we invested $686 million in our E&P operations (excluding the Vantage Energy acquisition), which was approximately 7% better than guidance. Our investments consisted of $504 million to drill and complete operated Marcellus and Ohio Utica wells, $67 million for non-operated Ohio Utica development and $115 million for land. In addition, we invested $105 million in our RMH midstream assets to construct our Ohio gas gathering systems.

1.

Please see "Supplemental Non-GAAP Financial Measures" for a description of Adjusted EBITDAX, adjusted net income (loss) and the related reconciliations thereof to net income (loss), the comparable GAAP financial measure.

Financial Position and Liquidity

On December 19, 2016, our upstream revolving credit facility borrowing base was increased to $1.45 billion, which represents a $700 million increase from the beginning of 2016 and a $450 million increase from the prior quarter which gives effect to the Pennsylvania oil and gas properties acquired in connection with the Vantage Energy acquisition.

As of December 31, 2016, our liquidity(1) position, excluding RMP, was $1.9 billion, comprised of $1.6 billion of upstream liquidity ($0.4 billion of cash on hand and $1.2 billion revolver availability)  and $296 million of RMH liquidity ($49 million of cash on hand and $247 million revolver availability). Our consolidated net debt to 2016 Further Adjusted EBITDAX(2) was 1.5x as of December 31, 2016.


1.

Liquidity is calculated by adding cash on hand plus availability on our revolving credit facilities.

2.

Please see "Supplemental Non-GAAP Financial Measures" for a description of Further Adjusted EBITDAX.

Fourth Quarter and Full Year 2016 Operational Results

As of December 31, 2016, our core Appalachian acreage position totaled approximately 248,000 net acres, consisting of approximately 185,000 net Marcellus acres in Pennsylvania and approximately 63,000 net Utica acres in Ohio. Across our acreage position we have identified over 1,100 undeveloped, highly economic drilling locations, including 861 net Marcellus locations in Pennsylvania and 241 net Utica locations in Ohio. In addition, we control approximately 105,000 net Utica acres in Pennsylvania and have identified 228 net undeveloped Utica locations in Pennsylvania.

Marcellus Shale

During the fourth quarter we turned to sales 18 gross (18 net) horizontal Marcellus wells with an average lateral length of 6,700 feet. During 2016, we turned to sales 36 gross (36 net) wells with an average lateral length of 7,000 feet. During the fourth quarter, we drilled 7 net and completed 9 net Marcellus wells for an average cost of $775 per lateral foot. In 2016, we also acquired 67 net producing wells pursuant to the Vantage Energy acquisition, exiting the year with 222 net operated horizontal Marcellus wells producing into sales.

In early 2016, we were able to leverage our continued healthy activity levels by investing capital in a trough service price environment to drive future, economic development. Due to these sustained activity levels, we have been able to hedge approximately 60% of our anticipated service costs for the next 12 - 24 months. In addition, the continuous improvement in peer-leading execution by our drilling and completion teams translated into multiple new company records throughout 2016. During 2016, we averaged 51 wells drilled per rig per year, which was approximately a 70% increase from the prior year average of 30 wells. In addition we completed an average of 6 stages per day in 2016, which was a 50% increase compared to the 2015 average of 4 stages per day. As a result, we turned 2016 operated wells to sales an average of approximately 40 days ahead of schedule. These efforts translated into a 34% reduction in our 2016 Marcellus drilling and completion costs compared to the 2015 average of $1,220 per lateral foot.

With respect to our acquired Vantage Energy assets, since assuming operational control in October 2016, we have drilled 7 horizontal wells, completed 6 wells and turned 2 wells to sales. Furthermore, as a result of acreage synergies and schedule optimization, we have increased the projected average lateral length on all expected 2017 wells drilled across the acquired acreage from 5,900 feet to over 8,000 feet. We believe that the combination of increased infill organic leasing and our growing economies of scale will allow us to continue to further extend lateral lengths across our Greene County acreage over time.

Utica Shale

During 2016, we turned to sales 20 gross (13 net) horizontal operated Utica wells with an average lateral length of 9,200 feet. In addition, we drilled 9 net and completed 9 net Utica wells during the fourth quarter for an average cost of $1,100 per lateral foot. We exited the year with 36 gross (24 net) operated horizontal Utica wells producing into sales and had a non-operated working interest in 76 gross (20 net) producing horizontal Ohio Utica wells.

Due to increased operational efficiencies, we turned 2016 operated wells to sales an average of approximately 20 days ahead of schedule. These efforts translated into a 30% reduction in our 2016 Utica drilling and completion costs compared to the 2015 average of $1,715 per lateral foot.

2016 Proved Reserves

As of December 31, 2016, proved reserves totaled 4.0 Tcfe, which represents a 2.3 Tcfe increase  from prior year proved reserves. Approximately 1.4 Tcfe of proved reserves were added organically through the drill-bit and 911 Bcfe were acquired (net of revisions), primarily from the Vantage Energy acquisition. During 2016, we replaced approximately 757% of produced reserves.

Proved Developed

Proved developed reserves grew to approximately 2.2 Tcfe, which represents a 115% increase from year-end 2015. Proved developed locations at year-end were comprised of 422 net producing wells (282 in Appalachia) plus 34 net non-producing wells (24 in Appalachia). At SEC pricing, the pre-tax PV-10(1) of our proved developed reserves totaled $1.3 billion, a 62% increase relative to the prior year PV-10 of $802 million. At NYMEX strip pricing(1), the pre-tax PV-10 of our year-end 2016 proved developed reserves was $2.2 billion, a 123% increase relative to prior year PV-10 of $988 million.

Undeveloped

As of December 31, 2016, we had 1,965 net undeveloped drilling locations, of which 143 (7.3%) were classified as proved undeveloped (PUD) with PUD reserves totaling 1.8 Tcfe, a 167% increase  from the prior year. Future development costs for these proved undeveloped reserves were estimated to be $0.58 per Mcfe, which represents a 24% per unit cost reduction as compared to the year-end 2015 estimated future development cost of $0.76 per Mcfe.


Estimated Proved Reserves as of December 31, 2016



Appalachia


Texas


Total


Net Wells

(App./TX)

Estimated proved reserves (Bcfe):









Proved developed reserves (PD)


1,916


262


2,178


305/151

Proved undeveloped reserves (PUD)


1,827



1,827


143/0

 Total proved reserves


3,743


262


4,005


448/151

PV-10 of proved reserves ($ in millions):









SEC pricing


$

1,418


$

150


$

1,568


Strip pricing(2)


$

3,009


$

222


$

3,231


Unproved, undeveloped locations(3)








1651/171

Total undeveloped locations(4)








1794/171

Undeveloped locations, %








8%/0%



1.

Please see "Supplemental Non-GAAP Financial Measure" for a description of PV-10 and the reconciliation thereof to standardized measure, the comparable GAAP financial measure.

2.

Strip pricing as of December 31, 2016: 2017 - $3.61; 2018 - $3.141; 2019 - $2.87; 2020 - $2.88.

3.

Represents management's calculation of net locations not included in total proved reserves net locations.

4.

Represents net PUD locations plus management's calculation of net locations not included in total proved reserves net locations.



Rice Midstream Holdings LLC

RMH controls one of the largest and most concentrated core dry gas acreage dedications in the Utica Shale, covering approximately 162,000 acres in Belmont and Monroe Counties with approximately 75% of its dedication from high-quality, third party customers. RMH also owns an approximate 92% common equity interest in GP Holdings, which in turn owns a 28% limited partner interest in Rice Midstream Partners LP (RMP) and 100% of its incentive distribution rights. For the fourth quarter 2016, RMH received $7.4 million of cash (net of ownership interest).

For the three months ended December 31, 2016, gathering volumes averaged 904 MDth/d, a 180% increase over the prior year quarter and an 11% increase relative to third quarter 2016, with 59% attributable to third-party volumes. Compression volumes were 432 MDth/d, an 11% decrease relative to third quarter 2016, with 51% attributable to third-party volumes. Gathering and compression revenues totaled $22.4 million. Operation and maintenance expense totaled $0.6 million, and operating loss was $4.4 million.

For the year ended December 31, 2016, gathering volumes averaged 708 MDth/d, a 187% increase over the prior year, with 62% attributable to third-party volumes. Compression volumes were 435 MDth/d, with 61% attributable to third-party volumes. Gathering and compression revenues totaled $63.9 million. Operation and maintenance expense totaled $3.0 million, and operating income was $13.6 million.

As of December 31, 2016, RMH had $247 million of availability on its revolving credit facility and $49 million of cash on hand, resulting in $296 million of total liquidity.

Rice Midstream Partners LP

RMP's concentrated gathering and compression acreage dedication in the Marcellus Shale core covers approximately 215,000 acres in Washington and Greene Counties with approximately 29,000 acres dedicated from high-quality, third party customers.

For the three months ended December 31, 2016, gathering volumes averaged 1,203 MDth/d, a 71% increase over the prior year quarter and a 26% increase relative to third quarter 2016, with 24% attributable to third-party volumes. Compression volumes were 825 MDth/d, a 778% increase over the prior year quarter and an 11% increase relative to third quarter 2016, with 36% attributable to third-party volumes. Fresh water delivery volumes were 321 million gallons or an average of 3.5 MMgal/d, a 59% increase over the prior year quarter and a 138% increase relative to third quarter 2016 due to increased Ohio Utica completion activity.

For the year ended December 31, 2016, gathering volumes averaged 983 MDth/d, a 52% increase over the prior year, with 27% attributable to third-party volumes. Compression volumes were 572 MDth/d, a 794% increase over the prior year, with 43% attributable to third-party volumes. Fresh water delivery volumes were 1,253 million gallons or an average of 3.4 MMgal/d, a 61% increase over the prior year, with 11% attributable to third-party volumes.

As of December 31, 2016, RMP had $660 million of availability on its revolving credit facility and $22 million of cash on hand, resulting in $682 million of total liquidity.

On January 20, 2017, RMP declared a quarterly distribution of $0.2505 per unit for the fourth quarter 2016. This represents an increase of $0.0135 per unit, or 6%, relative to third quarter 2016, which places RMP in the third tier of the IDR splits. The distribution was payable on February 16, 2017 to unitholders of record as of February 7, 2017.

RMP's fourth quarter and full-year 2016 results as well as 2017 guidance were released today and are available at www.ricemidstream.com.

Commodity Hedge Position

As depicted in the table below, we have 1,246 BBtu/d hedged in 2017 at a NYMEX weighted average floor price of $3.24 MMBtu, representing approximately 90% of expected production (based on the midpoint of guidance). Please see the "Derivatives Information" table at the end of this press release for more detailed information about our derivatives positions.


Total Fixed Price Derivatives

2017



2018



2019



2020



2021


NYMEX Volume Hedged (BBtu/d)

970



980



500



383



45


NYMEX Wtd Avg. Fixed Floor Price ($/MMBtu)

$

3.24



$

3.04



$

2.96



$

2.96



$

2.89


Total Volume Hedged (BBtu/d)

1,246



1,259



601



383



45


Total Wtd Avg. Fixed Floor Price ($/MMBtu)

$

3.05



$

2.87



$

2.87



$

2.96



$

2.89


Conference Call

Rice Energy will host a conference call on February 23, 2017 at 10:00 a.m. Eastern time (9:00 a.m. Central time) to discuss fourth quarter and full year 2016 financial and operating results. To listen to a live audio webcast of the conference call, please visit Rice Energy's website at www.riceenergy.com. A replay of the conference call will be available for two weeks and can also be accessed from our homepage.

About Rice Energy

Rice Energy Inc. is an independent natural gas and oil company focused on the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin.

For more information, please visit our website at www.riceenergy.com.

Forward Looking Statements

This release includes "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. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than historical facts included or incorporate herein that address activities, events or developments that we expect or anticipate will or may occur in the future, including such things as future capital expenditures (including the amount and nature thereof), projected operational results, production growth, basis exposure, hedging, the timing and number of well completions, forecasted gathering volumes, revenues, Adjusted EBITDAX, further Adjusted EBITDAX distribution growth, distributable cash flow, the timing of completion and nature of midstream projects, business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth of our business and operations, plans, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this release. Although we believe that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

We caution you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs 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; and risks related to joint venture operations. Information concerning these and other factors can be found in our filings with the Securities and Exchange Commission, including our Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this news release are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by us will be realized, or even if realized, that they will have the expected consequences to or effects on us, our business or operations. We have no intention, and disclaim any obligation, to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise.

Rice Energy Inc.

Consolidated Statements of Operations

(Unaudited)




Three Months Ended


Year Ended



December 31,


December 31,

(in thousands, except share data)


2016


2015


2016


2015

Operating revenues:









Natural gas, oil and natural gas liquids (NGL) sales


$

256,333



$

118,568



$

653,441



$

446,515


Gathering, compression and water services


27,601



14,424



101,057



49,179


Other revenue


112



3,095



24,408



6,447


Total operating revenues


284,046



136,087



778,906



502,141











Operating expenses:









Lease operating


18,450



9,350



50,007



44,356


Gathering, compression and transportation


38,954



29,197



123,852



84,707


Production taxes and impact fees


5,861



2,507



13,866



7,609


Exploration


5,225



1,212



15,159



3,137


Midstream operation and maintenance


4,932



6,024



23,157



16,988


Incentive unit expense (income)


6,859



(9,773)



51,761



36,097


Stock compensation expense


4,921



4,847



21,915



16,528


Impairment of gas properties


20,853



18,250



20,853



18,250


Impairment of goodwill




294,908





294,908


Impairment of fixed assets


20,462





23,057




General and administrative


29,082



24,607



96,803



86,510


Depreciation, depletion and amortization


121,323



94,787



368,455



322,784


Acquisition expense


4,938



1,111



6,109



1,235


Amortization of intangible assets


412



408



1,634



1,632


Other expense


1,508



2,896



27,308



5,567


Total operating expenses


283,780



480,331



843,936



940,308











Operating income (loss)


266



(344,244)



(65,030)



(438,167)


Interest expense


(25,883)



(24,009)



(99,627)



(87,446)


Other income


545



167



1,406



1,108


(Loss) gain on derivative instruments


(272,775)



89,019



(220,236)



273,748


Amortization of deferred financing costs


(3,129)



(1,403)



(7,545)



(5,124)


Loss before income taxes


(300,976)



(280,470)



(391,032)



(255,881)


Income tax benefit (expense)


96,483



6,217



142,212



(12,118)


Net loss


(204,493)



(274,253)



(248,820)



(267,999)


Less: Net loss (income) attributable to noncontrolling interests


34,604



(6,504)



(20,931)



(23,337)


Net loss attributable to Rice Energy Inc.


(169,889)



(280,757)



(269,751)



(291,336)


Less: Preferred dividends and accretion of redeemable noncontrolling interests


(8,467)





(28,450)




Net loss attributable to Rice Energy Inc. common stockholders


$

(178,356)



$

(280,757)



$

(298,201)



$

(291,336)


Weighted average number of shares of common stock - basic


201,878,421



136,384,591



162,225,505



136,344,076


Weighted average number of shares of common stock - diluted


201,878,421



136,384,591



162,225,505



136,344,076


Loss per share—basic


$

(0.88)



$

(2.06)



$

(1.84)



$

(2.14)


Loss per share—diluted


$

(0.88)



$

(2.06)



$

(1.84)



$

(2.14)


 



Rice Energy Inc.

Segment Results of Operations

(Unaudited)


Exploration and Production Segment




Three Months Ended


Year Ended



December 31,


December 31,

(in thousands, except volumes)


2016


2015


2016


2015










Operating volumes:









Natural gas production (MMcf)


104,053



57,201



302,322



199,831


Oil and NGL production (MBbls)


222



33



354



249


Total production (MMcfe)


105,384



57,399



304,443



201,328











Operating revenues:









Natural gas, oil and NGL sales


$

255,992



$

118,568



$

653,441



$

446,515


Other revenue


112



3,095



24,408



6,447


Total operating revenues


256,104



121,663



677,849



452,962











Operating expenses:









Lease operating


18,584



9,350



50,141



44,356


Gathering, compression and transportation


76,011



47,994



232,478



150,015


Production taxes and impact fees


5,861



2,507



13,866



7,609


Exploration


5,225



1,212



15,159



3,137


Incentive unit expense (income)


6,663



(10,056)



49,426



33,873


Stock compensation expense


3,936



3,140



13,971



11,029


Impairment of gas properties


20,853



18,250



20,853



18,250


Impairment of goodwill




294,908





294,908


Impairment of fixed assets


170





2,765




General and administrative


19,730



19,680



64,757



67,563


Depreciation, depletion and amortization


115,980



91,529



350,187



308,194


Other expense


92



3,049



25,653



5,075


Acquisition expense


4,886



108



5,500



108


Total operating expenses


277,991



481,671



844,756



944,117











Operating income (loss)


$

(21,887)



$

(360,008)



$

(166,907)



$

(491,155)











Average costs per Mcfe:









Lease operating


$

0.18



$

0.16



$

0.16



$

0.22


Gathering and compression


0.42



0.42



0.42



0.38


Transportation


0.30



0.42



0.35



0.36


Production taxes and impact fees


0.06



0.04



0.05



0.04


Exploration


0.05



0.02



0.05



0.02


General and administrative


0.19



0.34



0.21



0.34


Depreciation, depletion and amortization


1.10



1.59



1.15



1.53


 


Rice Midstream Holdings Segment




Three Months Ended


Year Ended



December 31,


December 31

(in thousands, except volumes)


2016


2015


2016


2015










Operating volumes:









Gathering volumes (MDth/d):


904



323



708



247


Compression volumes (MDth/d):


432



201



435



51











Operating results:









Operating revenues:









Gathering revenues


$

19,867



$

8,229



$

53,836



$

26,108


Compression revenues


2,558



1,254



10,098



1,256


Total operating revenues


22,425



9,483



63,934



27,364











Operating expenses:









Midstream operation and maintenance


553



1,143



2,971



2,078


Incentive unit expense


196



288



2,335



1,180


Acquisition expense




1,127



484



1,127


Impairment of fixed assets


20,292





20,292




Stock compensation expense


840



522



5,071



998


General and administrative


3,329



1,854



13,287



5,553


Depreciation, depletion and amortization


1,538



900



5,760



2,786


Other expense


125



(203)



125



(51)


Total operating expenses


26,873



5,631



50,325



13,671











Operating (loss) income


$

(4,448)



$

3,852



$

13,609



$

13,693


 

Rice Midstream Partners Segment




Three Months Ended


Year Ended



December 31,


December 31,

(in thousands, except volumes)


2016


2015


2016


2015










Operating volumes:









Gathering volumes (MDth/d):


1,203



703



983



647


Compression volumes (MDth/d):


825



94



572



64


Water services volumes (MMgal):


321



202



1,253



777











Operating results:









Operating revenues:









Gathering revenues


$

35,886



$

21,269



$

116,294



$

75,714


Compression revenues


5,874



(96)



15,805



1,497


Water services revenues


17,706



8,141



69,524



37,248


Total operating revenues


59,466



29,314



201,623



114,459











Operating expenses:









Midstream operation and maintenance


7,297



4,882



24,589



14,910


Incentive unit expense




(4)





1,044


Acquisition expense


52





125




Stock compensation expense


145



1,185



2,874



4,501


General and administrative


6,023



3,072



18,759



13,394


Depreciation, depletion and amortization


7,456



5,944



25,170



16,399


Amortization of intangible assets


412



408



1,634



1,632


Other expense


1,292



51



1,531



543


Total operating expenses


22,677



15,538



74,682



52,423











Operating income


$

36,789



$

13,776



$

126,941



$

62,036


 

Rice Energy Inc.
Supplemental Non-GAAP Financial Measures
(Unaudited)

Adjusted EBITDAX and Further Adjusted EBITDAX are supplemental non-GAAP financial measures that are used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net (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. We define Further Adjusted EBITDAX as Adjusted EBITDAX 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 a useful measure to the users of our financial statements because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our 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 the addition of a water revenue adjustment attributable to charges for fresh water delivery services and produced water hauling services provided by RMP to RICE, a charge that generates revenue for RMP but does not have a corresponding expense at the RICE 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 our 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. Our computations of Adjusted EBITDAX and Further Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that these measures are widely followed measures of operating performance used by investors.

The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).


Three Months Ended


Year Ended

(in thousands)

December 31, 2016


December 31, 2016

Adjusted EBITDAX reconciliation to net (loss):




Net loss

$

(204,493)



$

(248,820)


Interest expense

25,883



99,627


Depreciation, depletion and amortization

121,323



368,455


Impairment of fixed assets

20,462



23,057


Impairment of gas properties

20,853



20,853


Amortization of deferred financing costs

3,129



7,545


Amortization of intangible assets

412



1,634


Loss on derivative instruments(1)

272,775



220,236


Net cash receipts on settled derivative instruments(1)

34,720



201,071


Acquisition expense

4,938



6,109


Non-cash stock compensation expense

4,921



21,915


Non-cash incentive unit expense

6,859



51,761


Income tax (benefit) expense

(96,483)



(142,212)


Exploration expense

5,225



15,159


Acquisition break up fee



(1,939)


Other expense

1,383



6,511


Non-controlling interest attributable to midstream entities

(19,880)



(75,415)


Adjusted EBITDAX(2)

$

202,027



$

575,547




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.

 

Rice Energy Inc.
Supplemental Non-GAAP Financial Measure
(Unaudited)

Adjusted net income (loss) is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. We define adjusted net income (loss) as net income (loss) before impairment of gas properties, impairment of fixed assets, derivative fair value (gain) loss, net cash receipts on settled derivative instruments, incentive unit expense, acquisition expense and other non-recurring items. Adjusted net income (loss) is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

We believe that many investors use adjusted net income (loss) in making investment decisions and in evaluating our operational trends and our performance relative to other oil and gas producing companies.

The following table presents a reconciliation of the non-GAAP financial measure of adjusted net income (loss) to the GAAP financial measure of net income (loss).


Three Months Ended


Year Ended

(in thousands)

December 31, 2016


December 31, 2016

Reconciliation to net (loss) attributable to Rice Energy Inc:




Net (loss) attributable to Rice Energy Inc.

$

(169,889)



$

(269,751)


Impairment of gas properties

20,853



20,853


Impairment of fixed assets

20,462



23,057


Loss on derivative instruments(1)

272,775



220,236


Net cash receipts on settled derivative instruments(1)

34,720



201,071


Incentive unit expense

6,859



51,761


Acquisition expense

4,938



6,109


Other expense

1,383



6,511


Income tax effect of reconciling items

(116,483)



(200,309)


Adjusted net income attributable to Rice Energy Inc.

$

75,618



$

59,538




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 net income on a cash basis during the period the derivatives settled.

 

Rice Energy Inc.
Supplemental Non-GAAP Financial Measure
(Unaudited)

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. 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. 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:


Year Ended


Year Ended

(in millions)

December 31, 2016


December 31, 2015

Reconciliation to PV-10




Standardized measure of discounted future net cash flows

$

1,548



$

886


Discounted future net cash flows for income taxes

20




Discounted future net cash flows before income taxes (PV-10)

$

1,568



$

886


 

Rice Energy Inc.

Supplemental Balance Sheet Data

(Unaudited)


The table below provides supplemental balance sheet data as of December 31, 2016.


Supplemental Balance Sheet data (in thousands)

December 31, 2016

Cash and cash equivalents

$

470,043


Long-term debt


6.25% Senior Notes Due April 2022 (1)

$

887,977


7.25% Senior Notes Due May 2023 (2)

391,504


Senior Secured Revolving Credit Facility


Midstream Holdings Revolving Credit Facility

53,000


RMP Revolving Credit Facility

190,000


Total long-term debt

$

1,522,481


Net debt

$

1,052,438




1.

Net of unamortized deferred finance costs and original discount issuances of $12,023 (in thousands).

2.

Net of unamortized deferred finance costs and original discount issuances of $8,496 (in thousands).

 

Rice Energy Inc.

Derivatives Information

(Unaudited)


The table below provides data associated with our derivatives as of January 24, 2017 for the periods indicated:


All-In Fixed Price Derivatives

2017


2018


2019


2020


2021











NYMEX Natural Gas Swaps:










Volume Hedged (BBtu/d)

644



665



310



383



45


Wtd Average Swap Price ($/MMBtu)

$

3.28



$

3.00



$

2.95



$

2.96



$

2.89












NYMEX Natural Gas Collars:










Volume Hedged (BBtu/d)

271



285



170






Wtd Average Floor Price ($/MMBtu)

$

3.30



$

3.15



$

3.00



$



$


Wtd Average Call Price ($/MMBtu)

$

3.64



$

3.63



$

3.52



$



$












NYMEX Natural Gas Calls:










Volume Hedged (BBtu/d)

60



120



110



135




Wtd Average Price ($/MMBtu)

$

3.50



$

3.32



$

3.55



$

3.47



$












NYMEX Natural Deferred Puts:










Volume Hedged (BBtu/d)

55



30



20






Wtd Avg. Net Floor Price ($/MMBtu)

$

2.50



$

2.77



$

2.80



$



$












NYMEX Volume (BBtu/d)

970



980



500



383



45


NYMEX Volume Incl Calls (BBtu/d)

1,030



1,100



610



518



45


Swap, Collar & Put Floor ($/MMBtu)

$

3.24



$

3.04



$

2.96



$

2.96



$

2.89












WAHA Natural Gas Swaps










Volume Hedged (BBtu/d)

57



22



9






Wtd Average Swap Price ($/MMBtu)

$

3.07



$

3.01



$

3.29



$



$












Dominion Natural Gas Swaps










Volume Hedged (BBtu/d)

219



257



92






Wtd Average Swap Price ($/MMBtu)

$

2.24



$

2.23



$

2.34



$



$












Total Fixed Price Derivatives










Volume Hedged (BBtu/d)

1,246



1,259



601



383



45


Volume Hedged Incl. Calls (BBtu/d)

1,306



1,379



711



518



45


Wtd Average Swap Price ($/MMBtu)

$

3.05



$

2.87



$

2.87



$

2.96



$

2.89












Basis Contract Derivatives










Appalachian Basis










Volume Hedged (BBtu/d)

331



203



254



312



205


Wtd Average Swap Price ($/MMBtu)

$

(1.09)



$

(0.69)



$

(0.59)



$

(0.55)



$

(0.55)












Other Basis (Waha/MichCon/Gulf Coast)










Volume Hedged (BBtu/d)

550



300



167



73



20


Wtd Average Swap Price ($/MMBtu)

$

(0.13)



$

(0.15)



$

(0.15)



$

(0.14)



$

(0.12)












Total Basis Swaps










Volume Hedged (BBtu/d)

881



503



421



385



225


Wtd Average Swap Price ($/MMBtu)

$

(0.49)



$

(0.36)



$

(0.42)



$

(0.47)



$

(0.51)












WTI Swaps










Volume Hedged (Bbls/d)

50










Wtd Average Swap Price ($/bbl)

$

44.60



$



$



$



$












NGL Swaps










Volume Hedged (Bbls/d)

500










Wtd Average Swap Price ($/bbl)

$

15.13



$



$



$



$


 

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