Rice Energy Reports Fourth Quarter and Full-Year 2015 Results

Feb 24, 2016, 16:58 ET from Rice Energy Inc.

CANONSBURG, Pa., Feb. 24, 2016 /PRNewswire/ -- Rice Energy Inc. (NYSE: RICE) ("Rice Energy") today reported fourth quarter and full-year 2015 financial and operational results. Highlights to date include:

  • Fourth quarter net production averaged 624 MMcfe/d, 57% higher than fourth quarter 2014
  • Adjusted EBITDAX(1) of $132.2 million for the fourth quarter, a 51% increase above fourth quarter 2014
  • 2015 net production averaged 552 MMcfe/d, 101% higher than pro forma 2014 volumes and 5% above the high end of guidance
  • $431.5 million adjusted EBITDAX for 2015, a 75% increase above pro forma 2014
  • Adjusted realized natural gas price(2) of $3.39 and $3.19 per Mcf in the fourth quarter and full-year 2015, respectively
  • Average gathering throughput of 1,026 MDth/d for the fourth quarter, a 74% increase relative to fourth quarter 2014
  • Year-end 2015 proved reserves of 1.7 Tcfe, a 30% increase above the prior year
  • Proved reserves PV-10(1) of $1.4 billion at strip pricing, including $265 million of hedge value
  • Renegotiated third party gas gathering agreement for Western Greene County, PA acreage to increase dedication to Rice Midstream Partners (NYSE: RMP) by 19,000 gross acres
  • Formed Strike Force Midstream LLC with Gulfport Energy (NASDAQ: GPOR) ("GPOR"), a Utica Shale midstream joint venture in Ohio to develop gas gathering and compression assets
  • Closed strategic $375 million midstream equity investment by EIG Global Energy Partners
  • Year-end liquidity of $1.4 billion(3)(4) and leverage of 2.1x(1)(4)

Commenting on the results, Daniel J. Rice IV, Chief Executive Officer, said, "Our 2015 accomplishments highlight our unique asset quality, differentiated technical approach and our financial strength. Our core position within the most productive and economic windows of the Marcellus and Utica Shales provides a solid foundation that is supported by a balanced firm transportation portfolio and systematic hedging strategy to continue economically growing our business including expanding our world-class midstream assets. Our strategy continues to be focused on protecting the balance sheet while generating the highest return on investments to drive long-term value creation for our shareholders."

1.

Please see "Supplemental Non-GAAP Financial Measure" for a description of Adjusted EBITDAX, PV-10, and Further Adjusted EBITDAX.

2.

Adjusted realized price includes our firm transportation sales, net, and the impact of hedging.

3.

Excludes Rice Midstream Partners LP.

4.

Pro forma for the $375 million preferred equity investment that closed February 22, 2016.

 

Three Months Ended

Year Ended

2015 Consolidated Results

December 31, 2015

December 31, 2015

Total production (MMcfe)

57,399

201,328

Total production (MMcfe/d)

624

552

% Gas

100

%

99

%

  % Operated

94

%

93

%

  % Marcellus

72

%

74

%

Average realized prices per Mcf:

Natural gas price before effects of hedges

$

2.05

$

2.21

Natural gas price after effects of hedges(1)

$

3.39

$

3.18

Adjusted realized price

$

3.39

$

3.19

Average oil and NGL price per Bbl

$

23.64

$

21.79

Average costs per Mcfe:

Lease operating

$

0.16

$

0.22

Gathering, compression and transportation

$

0.51

$

0.42

Production taxes and impact fees

$

0.04

$

0.04

General and administrative(2)

$

0.43

$

0.43

Depreciation, depletion and amortization

$

1.65

$

1.60

Adjusted EBITDAX (in thousands)

$

132,153

$

431,510

Total midstream throughput (MDth/d)

1,026

894

% Third-party

25

%

22

%

Fourth Quarter 2015 Financial Results

During the fourth quarter, our net daily production averaged 624 MMcfe/d (100% natural gas), a 57% increase relative to fourth quarter 2014 production. This quarterly production growth was primarily driven by improved well performance and wells online ahead of schedule.

Fourth quarter average realized natural gas price, before the effect of hedges, was $2.05 per Mcf. After giving effect to hedges, our average natural gas price was $3.39 per Mcf. Approximately 91% of our fourth quarter production received favorable Gulf Coast, TCO and Midwest pricing, as compared to 76% of third quarter 2015 production, due to increasing premium market exposure through our firm transportation portfolio. Our average basis differential for the quarter was ($0.14) per MMBtu, while TETCO M2 and Dominion South averaged ($0.93) and ($0.92) per MMBtu, respectively, below NYMEX Henry Hub for the quarter.

Per unit cash production costs (lease operating; gathering, compression and transportation; and production taxes and impact fees) were $0.71 per Mcfe. Adjusted EBITDAX for the quarter was $132.2 million. We reported adjusted net income(3) of $22.0 million, or $0.16 per share, after excluding unrealized gains on derivative contracts and other non-recurring income and expense items.

1.

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

2.

Excludes equity compensation expense of $0.08 per Mcfe for the three and twelve months ended December 31, 2015.

3.

Please see "Supplemental Non-GAAP Financial Measure" for a description of Adjusted Net Income.

Full Year 2015 Financial Results

Net production averaged 552 MMcfe/d, a 101% increase as compared to pro forma 2014. Our 2015 average realized natural gas price, before the effect of hedges, was $2.21 per Mcf.  After giving effect to hedges, our average natural gas price was $3.18 per Mcf. The average adjusted realized price was $3.19 per Mcf.  Per unit cash production costs were $0.68 per Mcfe.  Adjusted EBITDAX during 2015 was $431.5 million. We reported adjusted net income of $0.8 million, or $0.01 per share.

During 2015, we invested $625 million to drill and complete Marcellus and Utica wells and invested $115 million in land activity. Additionally, we invested $248 million for our retained midstream assets.

Financial Position and Liquidity

As of December 31, 2015, our pro forma(1) liquidity position, excluding RMP, was $1.4 billion, consisting of $1.1 billion of upstream liquidity and $300 million of RMH liquidity.

Pro forma for the preferred equity transaction, our net debt to Further Adjusted EBITDAX(2) was 2.1 times for full year 2015 and 1.7 times for the fourth quarter 2015 annualized.

1.

Pro forma for the $375 million preferred equity transaction that closed on February 22, 2016.

2.

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

Operational Results

Marcellus Shale

Marcellus net production averaged 446 MMcfe/d during the fourth quarter, a 9% increase from the prior quarter and a 33% increase relative to fourth quarter 2014.

During the fourth quarter, we turned to sales 6 gross (6 net) horizontal Marcellus wells with an average lateral length of 7,499 feet at an average development cost of $1,192 per lateral foot.

In 2015, we placed online 42 gross (37 net) horizontal Marcellus wells. We exited 2015 with 120 net operated horizontal Marcellus wells producing into sales. As of December 31, 2015, our Marcellus leasehold position in Washington and Greene Counties, Pennsylvania, consisted of approximately 92,000 net acres and 487 undeveloped drilling locations.

In January 2016, we turned 5 gross (5 net) horizontal Marcellus wells to sales with an average lateral length of 6,600 feet.

The following table provides operational data through December 31, 2015, for our operated Marcellus wells. 

Periodic Flow Rates (MMcfe/d)

Period

Gross Operated Wells Turned Into Sales

Average Lateral Length (Feet)

0-90

91-180

181-360

361-720

D&C ($/Foot)

2010-2011

6

3,279

5.7

6.0

4.4

2.7

$

2,342

2012

9

5,731

9.2

10.0

6.8

4.1

$

1,583

2013

22

6,320

11.2

10.6

7.6

4.6

$

1,439

2014(1)

41

7,272

10.6

9.2

6.3

N/A

$

1,237

2015

42

7,298

9.4

8.3

N/A

N/A

$

1,181

 Total(2)

120

6,792

10.0

9.2

6.6

4.1

$

1,336

1.

Excludes 7 acquired producing wells.

2.

With the exception of wells turned into sales, totals represent averages weighted by number of wells.

Utica Shale

Utica net production averaged 174 MMcfe/d for the fourth quarter, a 196% increase relative to fourth quarter 2014.

In 2015, we placed online 14 gross (10 net) horizontal Utica wells, including one Pennsylvania Utica well. We exited the year with 17 gross (12 net) operated Utica wells producing into sales. At year-end 2015, we had a non-operated working interest in 36 gross (7 net) producing horizontal Ohio Utica wells.

As of December 31, 2015, our Ohio Utica leasehold position consisted of approximately 56,000 net acres and 215 undeveloped drilling locations. Our Pennsylvania Utica leasehold position in Washington and Greene Counties, consisted of approximately 49,000 net acres and 105 undeveloped drilling locations.

The following table provides operational data through December 31, 2015, for our operated Ohio Utica wells. 

Periodic Flow Rates (MMcf/d)

Period

Gross Operated Wells Turned Into Sales

Average Lateral Length (Feet)

0-90

91-180

181-360

361-720

D&C($/Foot)

2014

3

8,238

14.3

15.3

16.2

N/A

$

2,457

2015

13

9,759

15.5

14.3

N/A

N/A

$

1,653

Total(1)

16

9,474

15.3

14.5

16.2

N/A

$

1,802

1.

With the exception of wells turned into sales, totals represent averages weighted by number of wells.

Midstream Segment

For the fourth quarter, average daily throughput was 1,026 MDth/d, a 74% increase relative to fourth quarter 2014, with 25% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $38.8 million for the quarter. Operation and maintenance expenses totaled $6.0 million, and operating income was $17.6 million

For the year ended December 31, 2015, average daily throughput was 894 MDth/d, with 22% attributable to third-party volumes. Gathering, compression and water distribution revenues totaled $141.8 million. Operation and maintenance expenses totaled $17.0 million, and operating income was $75.7 million.

Rice Midstream Partners LP (NYSE: RMP)("RMP" or the "Partnership")

Average daily throughput for the fourth quarter was 703 MDth/d, a 36% increase relative to fourth quarter 2014, with 18% attributable to third-party volumes. Water services volumes totaled 202 million gallons, with 58% attributable to third-party volumes. The Partnership reported net income attributable to limited partners of $12.5 million, or $0.18 per limited partner unit.

As of December 31, 2015, RMP had $307 million of undrawn capacity on its revolving credit facility and $8 million of cash on hand, resulting in $315 million of total liquidity.

On January 22, 2016, RMP declared its quarterly distribution of $0.1965 per unit for the fourth quarter 2015, an increase of $0.003 per unit relative to third quarter 2015. The distribution was payable on February 11, 2016 to unitholders of record as of February 2, 2016.

Subsequent to year-end, Rice renegotiated its third party gas gathering agreement for acreage acquired from Chesapeake Appalachia, L.L.C. in August 2014 to increase the acreage dedication from Rice to RMP by 19,000 gross acres to approximately 93,000 gross acres. RMP will gather all production above the first 40 MDth/d, as well as pursue additional third party gathering and water opportunities surrounding this dedication.

Rice Midstream Holdings LLC

Average daily throughput for the fourth quarter of 2015 was 323 MDth/d, a 336% increase relative to fourth quarter 2014, with 40% attributable to third-party volumes. For the year ended December 31, 2015, average daily throughput was 247 MDth/d, with 38% attributable to third-party volumes.

On February 1, 2016, our wholly-owned subsidiary, Strike Force Holdings LLC, and a subsidiary of Gulfport Energy Corporation (NASDAQ: GPOR) completed the formation of its previously announced Utica Shale midstream JV, Strike Force Midstream LLC ("Strike Force"). RMH owns 75% of Strike Force and will act as the operator, and GPOR owns the remaining 25% and dedicated approximately 75,000 leasehold acres. Strike Force will develop natural gas gathering assets to support GPOR's dry gas Utica Shale development in eastern Belmont County and Monroe County, Ohio and will pursue additional third party opportunities within approximately 319,000 acres in the AMI. Strike Force will be supported by long-term, fee-based service agreements with GPOR. Construction of the assets is underway and phase one was completed ahead of schedule, allowing GPOR to commence first flow on a lateral that connected two existing dry gas gathering systems.

2015 Proved Reserves

Proved reserves increased by 30% from year-end 2014 to over 1.7 Tcfe at December 31, 2015. The Marcellus Shale accounted for approximately 75% of our total proved reserves and the Utica Shale accounted for the substantial remainder. Our year-end 2015 proved reserves were 99.8% natural gas with an 8-year estimated reserve life, based on 2015 production. As of December 31, 2015, approximately 15% of our 1,369 total net identified drilling locations were classified as proved.

Estimated Proved Reserves as of December 31, 2015

SEC Pricing

Strip Pricing(1)

$2.59/MMBtu

Net Reserves (Bcfe)

PV-10

(in millions)

Net Reserves (Bcfe)

PV-10

(in millions)

Net Locations

Proved developed reserves

1,015

$

802

1,053

$

935

156

Proved undeveloped reserves

685

85

698

246

54

Hedge value

408

265

 Total proved reserves

1,700

$

1,295

1,751

$

1,446

210

Un-booked locations(2)

1,159

Total Estimated Locations

1,369

Percent developed locations

11

%

1.

Strip pricing: 2016 - $2.45; 2017 - $2.78; 2018 - $2.90; 2019 - $3.01.

2.

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

Proved Developed Reserves

Proved developed reserves increased by 57% from year-end 2014 to approximately 1.0 Tcfe, as of December 31, 2015. Approximately 60% of our total proved reserves were classified as proved developed, as compared to 49% at year-end 2014. There were 156 net wells categorized as proved developed at year-end 2015, consisting of 143 net producing wells and 13 net non-producing wells.

Proved Undeveloped Reserves

Proved undeveloped reserves increased by 3% from year-end 2014 to approximately 685 Bcfe, as of December 31, 2015. There were 54 net locations categorized as proved undeveloped at year-end 2015, including 15 net Utica locations. Based on 2015 well cost assumptions, our 685 Bcfe of proved undeveloped reserves will require an estimated $517 million of future development capital over the next five years, which results in an estimated average development cost of $0.75 per Mcfe for our proved undeveloped reserves. 

Proved Reserves PV-10

Using NYMEX strip pricing, the pre-tax present value discounted at 10% (pre-tax PV-10) for our year-end 2015 total proved reserves was $1.4 billion, including $265 million of hedge value. Our pre-tax PV-10 value of our proved developed reserves was $935 million.

Using SEC pricing, the pre-tax PV-10 of our year-end 2015 total proved reserves was $1.3 billion, including $408 million of hedge value. Our pre-tax PV-10 value of our proved developed reserves was $802 million. Our estimated proved reserves and PV-10 value were determined using an SEC Henry Hub spot price of $2.59 per MMBtu, which is based on the 12-month unweighted arithmetic average of the first day of the month price for each month in the January through December 2015 period and is not indicative of current forward prices.

Commodity Hedge Position

As depicted in the table below, we have 662 BBtu/d hedged in 2016 at a weighted average floor price of $3.26 MMBtu. Our 2016 hedges cover 87% of our 2016 production (based on the midpoint of guidance). Additionally, for the first quarter of 2016 we have 556 BBtu/d hedged at a weighted average floor price of $3.30 per MMBtu. For 2017 we have 563 BBtu/d hedged at a weighted average floor price of $3.14 MMBtu. Our 2017 hedges are expected to cover more than half of our 2017 production. 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

2016

2017

2018

2019

Volume Hedged Excl. Calls (BBtu/d)

662

563

285

150

Weighted Average Swap Price ($/MMBtu)

$

3.26

$

3.14

$

3.16

$

3.11

Firm Transportation and Realized Gas Pricing

In 2016, we anticipate that approximately 70% of our production will be transported to premium gas markets outside of Appalachia. The following tables provide basis exposure as a percentage of our production and average differentials to NYMEX for actual results through December 31, 2015 and estimated results for the first quarter of 2016 and full year 2016 and 2017.

Basis Exposure

Actual

Estimated

4Q15

1Q16

FY 2016

FY 2017

    Gulf Coast

47%

46%

46%

51%

    TCO

18%

14%

9%

7%

    Midwest/Dawn

26%

18%

14%

9%

    DTI / M2 / M3

9%

22%

31%

33%

 

Realized Price

Actual

Estimated(1)

4Q15

1Q16

FY 2016

FY 2017

NYMEX Henry Hub price ($/MMBtu)

$

2.23

$

2.08

$

2.16

$

2.58

Average basis impact ($/MMBtu)

(0.14)

(0.28)

(0.35)

(0.32)

Firm transportation fuel & variables ($/MMBtu)

(0.15)

(0.14)

(0.12)

(0.13)

Btu uplift (MMBtu/Mcf)

0.11

0.10

0.11

0.14

Pre-hedge realized price ($/Mcf)

2.05

1.76

1.80

2.27

Realized hedging gain (loss) ($/Mcf)

1.34

1.03

0.96

0.34

Post-hedge realized price ($/Mcf)

3.39

2.79

2.76

2.61

1.

NYMEX price as of 2/18/16.

Conference Call

Rice Energy will host a conference call on February 25, 2016 at 9:30 a.m. Eastern time (8:30 a.m. Central time) to discuss fourth quarter and full year 2015 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.

Please visit www.riceenergy.com to view a presentation containing fourth quarter and full year 2015 information.

About Rice Energy

Rice Energy Inc. is an independent natural gas and oil company engaged in 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 (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). 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 EBITDA, distribution growth, distributable cash flow, private placement by the Partnership, the midstream JV, 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 and oil. These risks include, but are not limited to: commodity price volatility; the availability of capital on an economic basis; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; legislative and regulatory changes adversely affecting the industry; transportation capacity constraints and interruptions; the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development expenditures. Furthermore, the acquisition of the water services business by the Partnership, the concurrent private placement by the Partnership and related transactions may not be completed as described or at all. 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)

2015

2014

2015

2014

Operating revenues:

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

$

118,568

$

112,385

$

446,515

$

359,201

Firm transportation sales, net

98

14,386

3,450

26,237

Gathering, compression and water services

14,424

2,627

49,179

5,504

Other revenue

2,997

2,997

Total operating revenues

136,087

129,398

502,141

390,942

Operating expenses:

Lease operating

9,350

8,565

44,356

24,971

Gathering, compression and transportation

29,197

13,154

84,707

35,618

Production taxes and impact fees

2,507

2,024

7,609

4,647

Exploration

1,212

2,436

3,137

4,018

Midstream operation and maintenance

6,024

1,043

16,988

4,607

Incentive unit (income) expense

(9,773)

4,266

36,097

105,961

Stock compensation expense

4,847

2,279

16,528

5,553

Impairment of gas properties

18,250

18,250

Impairment of goodwill

294,908

294,908

General and administrative

24,607

19,284

86,510

56,017

Depreciation, depletion and amortization

94,787

64,358

322,784

156,270

Acquisition expense

1,111

92

1,235

2,339

Amortization of intangible assets

408

408

1,632

1,156

Gain from sale of interest in gas properties

(953)

Other expense

2,896

207

6,520

207

Total operating expenses

480,331

118,116

940,308

401,364

Operating (loss) income

(344,244)

11,282

(438,167)

(10,422)

Interest expense

(24,009)

(11,454)

(87,446)

(50,191)

Gain on purchase of Marcellus joint venture

203,579

Other income

167

713

1,108

893

Gain on derivative instruments

89,019

181,120

273,748

186,477

Amortization of deferred financing costs

(1,403)

(766)

(5,124)

(2,495)

Loss on extinguishment of debt

(3,720)

(7,654)

Write-off of deferred financing costs

(6,896)

Equity in (loss) income of joint ventures

(2,656)

(Loss) income before income taxes

(280,470)

177,175

(255,881)

310,635

Income tax benefit (expense)

6,217

(72,813)

(12,118)

(91,600)

Net (loss) income

(274,253)

104,362

(267,999)

219,035

Less: Net income attributable to non-controlling interests

(6,504)

(581)

(23,337)

(581)

Net (loss) income attributable to Rice Energy Inc.

$

(280,757)

$

103,781

$

(291,336)

$

218,454

Weighted average number of shares of common stock - basic

136,384,591

136,280,766

136,344,076

128,151,171

Weighted average number of shares of common stock - diluted

136,384,591

136,352,435

136,344,076

128,225,155

(Loss) earnings per share—basic

$

(2.06)

$

0.76

$

(2.14)

$

1.70

(Loss) earnings per share—diluted

$

(2.06)

$

0.76

$

(2.14)

$

1.70

 

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)

2015

2014

2015

2014

Operating volumes:

Natural gas production (MMcf)

57,201

36,076

199,831

97,172

Oil and NGL production (MBbls)

33

91

249

94

Total production (MMcfe)

57,399

36,621

201,328

97,737

Operating revenues:

Natural gas, oil and NGL sales

$

118,568

$

112,385

$

446,515

$

359,201

Firm transportation sales, net

98

14,386

3,450

26,237

Other revenue

2,997

2,997

Total operating revenues

121,663

126,771

452,962

385,438

Operating expenses:

Lease operating

9,350

8,565

44,356

24,971

Gathering, compression and transportation

47,994

14,748

150,015

37,414

Production taxes and impact fees

2,507

2,024

7,609

4,647

Exploration

1,212

2,437

3,137

4,018

Incentive unit (income) expense

(10,056)

(4,012)

33,873

86,020

Stock compensation expense

3,140

1,661

11,029

4,532

Impairment of gas properties

18,250

18,250

Impairment of goodwill

294,908

294,908

General and administrative

19,680

12,357

67,563

41,697

Depreciation, depletion and amortization

91,529

62,584

308,194

151,900

Gain from sale of interest in gas properties

(953)

Other expense

3,049

6,028

Acquisition expense

108

58

108

820

Total operating expenses

481,671

100,422

944,117

356,019

Operating (loss) income

$

(360,008)

$

26,349

$

(491,155)

$

29,419

Average costs per Mcfe:

Lease operating

$

0.16

$

0.23

$

0.22

$

0.26

Gathering and compression

0.42

0.38

Transportation

0.42

0.40

0.36

0.38

Production taxes and impact fees

0.04

0.06

0.04

0.05

Exploration

0.02

0.07

0.02

0.04

General and administrative

0.34

0.34

0.34

0.43

Depreciation, depletion and amortization

1.59

1.71

1.53

1.55

 

Midstream Segment

Three Months Ended

Year Ended

December 31,

December 31,

(in thousands, except volumes)

2015

2014

2015

2014

Operating volumes:

Gathering volumes (MDth/d):

1,027

592

894

402

Compression volumes (MDth/d):

295

115

Water services volumes (MMgal):

202

777

Operating revenues:

Gathering revenues

$

29,498

$

4,589

$

101,822

$

7,300

Compression revenues

1,158

(368)

2,753

Water services revenues

8,141

37,248

Total operating revenues

38,797

4,221

141,823

7,300

Operating expenses:

Midstream operation and maintenance

6,024

1,043

16,988

4,607

Incentive unit expense

284

8,278

2,224

19,941

Stock compensation expense

1,707

618

5,499

1,021

General and administrative

4,926

6,927

18,947

14,320

Depreciation, depletion and amortization

6,844

1,773

19,185

4,370

Amortization of intangible assets

408

408

1,632

1,156

Acquisition costs

1,127

35

1,127

1,519

        Other expense

(152)

207

492

207

Total operating expenses

21,168

19,289

66,094

47,141

Operating income (loss)

$

17,629

$

(15,068)

$

75,729

$

(39,841)

 

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

Adjusted EBITDAX 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 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. Adjusted EBITDAX is not 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 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 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. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from 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. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

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, 2015

December 31, 2015

Adjusted EBITDAX reconciliation to net income (loss):

Net loss

$

(274,253)

$

(267,999)

Interest expense

24,009

87,446

Depreciation, depletion and amortization

94,787

322,784

Impairment of gas properties

18,250

18,250

Impairment of goodwill

294,908

294,908

Amortization of deferred financing costs

1,403

5,124

Amortization of intangible assets

408

1,632

Gain on derivative instruments(1)

(89,019)

(273,748)

Net cash receipts on settled derivative instruments(1)

76,228

193,908

Acquisition expense

1,111

1,235

Non-cash stock compensation expense

4,847

16,528

Non-cash incentive unit (income) expense

(9,773)

36,097

Income tax (benefit) expense

(6,217)

12,118

Gain from sale of interest in gas properties

(953)

Exploration expense

1,212

3,137

Other expense

756

4,380

Non-controlling interest

(6,504)

(23,337)

Adjusted EBITDAX

$

132,153

$

431,510

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.

 

The following table presents a reconciliation of the non-GAAP financial measure of Further Adjusted EBITDAX to Adjusted EBITDAX.

Three Months Ended

Year Ended

(in thousands)

December 31, 2015

December 31, 2015

Further Adjusted EBITDAX reconciliation:

Adjusted EBITDAX

$

132,153

$

431,510

Non-controlling interest(1)

6,504

23,337

Water revenue adjustment(2)

5,577

27,336

Further Adjusted EBITDAX

$

144,234

$

482,183

Net Debt(1)

$

988,649

Net Debt / LTM EBITDAX

2.1

Net Debt / LQA EBITDAX

1.7

1.

Add back non-controlling interest to Adjusted EBITDAX to calculate leverage metrics.

2.

Add back RMP water distribution revenue from RICE's working interest share of the water fees that was eliminated in the Rice consolidation.

 

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 derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments incentive unit 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 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

December 31, 2015

Year Ended

December 31, 2015

(in thousands)

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

Net loss attributable to Rice Energy Inc.

$

(280,757)

$

(291,336)

Impairment of gas properties, net of tax

43,792

12,675

Impairment of goodwill

294,908

294,908

Gain on derivative instruments, net of tax(1)

(213,609)

(190,118)

Net cash receipts on settled derivative instruments, net of tax(1)

182,917

134,669

Incentive unit (income) expense

(9,773)

36,097

Other expense, net of tax

1,815

3,042

Acquisition expense, net of tax

2,666

858

Adjusted net income (loss) attributable to Rice Energy Inc.

$

21,959

$

795

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 mist 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 to the standardized measure of discounted future net cash flows:

Year Ended December 31, 2015

Year Ended December 31, 2014

(in millions)

Reconciliation to PV-10

Standardized measure of discounted future net cash flows

$

886

$

1,308

Discounted future net cash flows for income taxes

436

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

$

886

$

1,744

 

Rice Energy Inc. Derivatives Information (Unaudited)

The table below provides data associated with our derivatives as of February 23, 2016 for the periods indicated:

All-In Fixed Price Derivatives

2016

2017

2018

2019

2020

NYMEX Natural Gas Swaps:

Volume Hedged (BBtu/d)

581

288

5

20

Weighted Average Swap Price ($/MMBtu)

$

3.32

$

3.27

$

3.60

$

3.23

$

NYMEX Natural Gas Collars:

Volume Hedged (BBtu/d)

50

220

280

130

Weighted Average Floor Price ($/MMBtu)

$

2.91

$

3.13

$

3.16

$

3.09

$

Weighted Average Collar Price ($/MMBtu)

$

3.60

$

3.61

$

3.62

$

3.60

$

NYMEX Natural Gas Calls:

Volume Hedged (BBtu/d)

50

70

70

65

Weighted Average Price ($/MMBtu)

$

$

3.60

$

3.50

$

3.50

$

3.44

NYMEX Natural Deferred Puts:

Volume Hedged (BBtu/d)

55

Weighted Avg. Net Floor Price ($/MMBtu)

$

$

2.50

$

$

$

NYMEX Volume Excl. Calls (BBtu/d)

631

563

285

150

NYMEX Volume Incl. Calls (BBtu/d)

631

613

355

220

65

Swap, Collar & Put Floor ($/MMBtu)

$

3.29

$

3.14

$

3.16

$

3.11

$

Dominion Natural Gas Swaps

Volume Hedged (BBtu/d)

31

Weighted Average Swap Price ($/MMBtu)

$

2.62

$

$

$

$

Total Fixed Price Derivatives

Volume Hedged Excl. Calls (BBtu/d)

662

563

285

150

Volume Hedged Incl. Calls (BBtu/d)

662

613

355

220

65

Weighted Average Swap Price ($/MMBtu)

$

3.26

$

3.14

$

3.16

$

3.11

$

Basis Contract Derivatives

TCO Basis Swaps

Volume Hedged (BBtu/d)

44

27

19

10

Weighted Average Swap Price ($/MMBtu)

$

(0.32)

$

(0.33)

$

(0.40)

$

(0.38)

$

Dominion Basis Swaps

Volume Hedged (BBtu/d)

76

98

165

150

68

Weighted Average Swap Price ($/MMBtu)

$

(1.01)

$

(0.89)

$

(0.67)

$

(0.63)

$

(0.64)

M2 Basis Swaps

Volume Hedged (BBtu/d)

61

65

Weighted Average Swap Price ($/MMBtu)

$

(1.03)

$

(1.01)

$

$

$

MichCon Basis Swaps

Volume Hedged (BBtu/d)

24

4

4

20

20

Weighted Average Swap Price ($/MMBtu)

$

(0.01)

$

(0.04)

$

(0.04)

$

(0.12)

$

(0.12)

ELA Basis Swaps

Volume Hedged (BBtu/d)

110

80

40

10

Weighted Average Swap Price ($/MMBtu)

$

(0.10)

$

(0.09)

$

(0.08)

$

(0.10)

$

Chicago Basis Swaps

Volume Hedged (BBtu/d)

40

10

10

Weighted Average Swap Price ($/MMBtu)

$

(0.05)

$

(0.16)

$

(0.19)

$

$

ANR SE Basis Swaps

Volume Hedged (BBtu/d)

35

Weighted Average Swap Price ($/MMBtu)

$

(0.10)

$

$

$

$

Physical Triggered Basis

Appalachian Fixed Basis (Physical)

Volume Hedged (BBtu/d)

21

20

Weighted Average Swap Price ($/MMBtu)

$

(0.79)

$

$

$

$

(0.65)

MichCon Fixed Basis (Physical)

Volume Hedged (BBtu/d)

10

10

8

Weighted Average Swap Price ($/MMBtu)

$

0.05

$

0.05

$

0.05

$

$

Gulf Coast Fixed Basis (Physical)

Volume Hedged (BBtu/d)

100

100

100

92

42

Weighted Average Swap Price ($/MMBtu)

$

(0.17)

$

(0.17)

$

(0.17)

$

(0.16)

$

(0.15)

Total Basis Swaps (Financial + Physical)

Volume Hedged (BBtu/d)

521

394

346

282

150

Weighted Average Swap Price ($/MMBtu)

$

(0.39)

$

(0.47)

$

(0.40)

$

(0.41)

$

(0.44)

 

The table below provides supplemental balance sheet data as of December 31, 2015.

Supplemental Balance Sheet data (in thousands)

December 31, 2015

Cash and cash equivalents

$

151,901

Long-term debt

6.25% Senior Notes Due April 2022

$

900,000

7.25% Senior Notes Due May 2023

397,222

Senior Secured Revolving Credit Facility

Midstream Holdings Revolving Credit Facility

17,000

RMP Revolving Credit Facility

143,000

Total long-term debt

$

1,457,222

Net debt

$

1,305,321

 

The table below outlines our firm transportation capacity by pipeline.

Project

Pipeline

Start Date

Volume (Dth/d)

Term

Market

TEAM South

TETCO

Sept-14

270,000

38 Yrs

Gulf Coast

Westside Expansion

TCO

Nov-14

125,000

10 Yrs

TCO/Gulf Coast

Rockies Express Reversal

REX

Aug-15

175,000

20 Yrs

Midwest/Gulf Coast

Union Town to Gas City

TETCO

Sept-15

86,500

10 Yrs

Midwest/Gulf Coast

OPEN

TETCO

Sept-15

50,000

20 Yrs

Gulf Coast

ET Rover

Rover

Nov-17

100,000

15 Yrs

Canada

Access South

TETCO

Nov-17

320,000

25 Yrs

Gulf Coast

 

Logo - http://photos.prnewswire.com/prnh/20140123/DA51701LOGO

 

SOURCE Rice Energy Inc.



RELATED LINKS

http://www.riceenergy.com