Exhibit 99.1
FOR IMMEDIATE RELEASE
Rice Energy Reports Fourth Quarter and Full Year 2014 Results
CANONSBURG, Pa., March. 12, 2015 /PRNewswire/ - Rice Energy Inc. (NYSE: RICE) (“Rice Energy”) today reported fourth quarter and full-year 2014 financial and operational results. Highlights during the year include:
| | • | | Average net production of 398 MMcfe/d in fourth quarter 2014, a 158% increase above prior year quarter pro forma volumes(1)and a 61% increase over third quarter 2014 |
| | • | | Adjusted EBITDAX(2) of $87 million for fourth quarter 2014, a 123% increase over pro forma fourth quarter 2013 |
| | • | | 2014 average net production of 274 MMcfe/d, a 118% increase above full-year 2013 pro forma volumes |
| | • | | Adjusted EBITDAX of $247 million for the full year 2014 |
| | • | | Increased core acreage position to approximately 141,000 net acres as of December 31, 2014, consisting of 86,000 net acres in southwestern Pennsylvania and 55,000 net acres in Ohio, a 57% increase above year-end 2013 leasehold position |
| | • | | Year-end 2014 proved reserves of 1.3 Tcfe, a 117% increase from year-end 2013 pro forma reserves |
| | • | | Increased proved PV-10(2) value to $1.7 billion, an increase of 146% over 2013 pro forma PV-10 value |
| | • | | Completed successful $474 million IPO of Rice Midstream Partners LP in December 2014 |
| | • | | Strong year-end 2014 liquidity position of approximately $1 billion to fund 2015 upstream and retained midstream capital investments |
Commenting on the results, Daniel J. Rice IV, Chief Executive Officer, said, “Our accomplishments in 2014 reflect our team’s capabilities and opportunistic mindset. Last year, we took two companies public, Rice Energy and Rice Midstream Partners, we increased our core Marcellus and Utica acreage positions by approximately 50%, and we nearly tripled our net production. We achieved these milestones while acting as good stewards of the environment and our stakeholders’ capital. With ample liquidity and 100% core Marcellus and Utica assets, we are well-positioned to drive long term value creation for our shareholders in 2015 and beyond.”
| (1) | References to pro forma volumes and reserves throughout this earnings release give effect to our acquisition of the remaining 50% interest in our Marcellus joint venture from Alpha Natural Resources, Inc. on January 29, 2014. |
| (2) | Please see “Supplemental Non-GAAP Financial Measures” for a description of Adjusted EBITDAX and PV-10. |
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As of December 31, 2014, Rice owns a 50% limited partner interest and all of the incentive distribution rights in Rice Midstream Partners LP (“RMP”). RMP’s financial results since the closing of its IPO on December 22, 2014, are consolidated with Rice Energy’s results. RMP released fourth quarter 2014 results today and are available atwww.ricemidstream.com.
| | | | | | | | |
| 2014 Consolidated Results | | Three Months Ended
December 31, 2014 | | | Year Ended
December 31, 2014 | |
Natural gas production (MMcf) | | | 36,076 | | | | 97,172 | |
Oil and natural gas liquids (NGL) production (MBbls) | | | 91 | | | | 94 | |
Total production (MMcfe) | | | 36,621 | | | | 97,737 | |
| | |
Average realized prices per Mcf: | | | | | | | | |
Natural gas price before effects of hedges | | $ | 3.00 | | | $ | 3.65 | |
Natural gas price after effects of hedges(1) | | | 3.06 | | | | 3.46 | |
Adjusted realized price(2) | | | 3.46 | | | | 3.73 | |
Average oil and NGL price per Bbl | | | 45.18 | | | | 46.07 | |
| | |
Average costs per Mcfe: | | | | | | | | |
Lease operating | | $ | 0.23 | | | $ | 0.26 | |
Gathering, compression and transportation | | | 0.39 | | | | 0.41 | |
Production taxes and impact fees | | | 0.06 | | | | 0.05 | |
General and administrative | | | 0.53 | | | | 0.57 | |
Depletion, depreciation and amortization | | | 1.76 | | | | 1.60 | |
| | |
Adjusted EBITDAX (in thousands) | | $ | 87,335 | | | $ | 246,610 | |
| (1) | The effect of hedges includes realized gains and losses on commodity derivative transactions. |
| (2) | Adjusted realized price includes our firm transportation sales, net, and the impact of hedging. |
Fourth Quarter 2014 Financial Results
During the fourth quarter 2014, our net production averaged 398 MMcfe/d, a 61% increase over third quarter 2014 volumes and 158% over pro forma fourth quarter 2013 production of 154 MMcfe/d. Total net production for the quarter was comprised of 36.1 Bcf of natural gas and 91 MBbls of oil and NGLs. Our fourth quarter 2014 realized natural gas price, before the effect of hedges, was $3.00 per Mcf. After giving effect to hedges, our fourth quarter 2014 average natural gas price was $3.06 per Mcf. Our average adjusted realized price, including our firm transportation sales and the impact of hedges, was $3.46 per Mcf. Our average realized oil and NGL price was $45.18 per Bbl. Per unit cash production costs (lease operating; gathering, compression and transportation; and production taxes and impact fees) were $0.68 per Mcfe. Adjusted EBITDAX for the quarter was $87 million. We reported adjusted net income of $4 million, or $0.03 per share, after excluding unrealized gains and losses on derivative contracts and other non-recurring income and expense items.
Full Year 2014 Financial Results
Our 2014 pro forma production averaged 274 MMcfe/d, an increase of 118% compared to the pro forma prior year period. Total pro forma production for 2014 was comprised of 99.6 Bcf of natural gas and 94 MBbls of oil and NGLs. Our 2014 realized natural gas price, before the effect of hedges, was $3.65 per Mcf. After giving effect to hedges, our 2014 average natural gas price was $3.46 per Mcf. Our averaged adjusted realized price, including firm transportation sales and the impact of hedges, was $3.73 per Mcf. Our average realized oil and NGL price was $46.07 per Bbl. Per unit cash production costs were $0.72 per Mcfe. Adjusted EBITDAX for the full year 2014 was $247 million. We reported adjusted net loss of $34 million, or ($0.26) per share.
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During 2014 we invested approximately $1.1 billion, excluding acquisitions, for drilling and completion, leasehold and midstream capital investments. Approximately $580 million was invested in drilling and completing Marcellus and Utica wells, an additional $250 for organic leasing activity and $300 for midstream infrastructure buildout. In addition, we spent approximately $110 million to acquire Pennsylvania gas gathering assets and $330 million for our western Greene County acreage acquisition. Our total capital invested during 2014 was $1.5 billion.
E&P Segment
Marcellus Shale
During the fourth quarter, we completed and turned to sales 22 gross (19 net) horizontal Marcellus wells with an average lateral length of 7,200 feet. This includes 5 gross (4 net) wells that were completed and turned to sales in mid-December, approximately six weeks ahead of schedule. We turned to sales 36 net wells during 2014 and exited the year with 78 net operated Marcellus wells and 3 net Upper Devonian wells producing into sales.
Year to date, we have turned 8 Marcellus wells to sales with an average lateral length of 6,200 feet and 73% working interest.
The following table provides certain operational data as of March 1, 2015, related to the 22 gross operated Marcellus wells brought online during the fourth quarter 2014.
| | | | | | | | |
Wells per Pad | | Average Lateral
Length (Feet) | | Periodic
Flow Rates
(MMcfe/d)
0-60 Days | | Average
D&C ($/Foot)(1) | |
5 | | 7,897 | | 9.4 | | $ | 919 | |
3 | | 6,499 | | 7.9 | | $ | 1,334 | |
9 | | 6,555 | | 8.2 | | $ | 1,291 | |
5 | | 5,698 | | 5.8 | | $ | 1,232 | |
| (1) | Drilling and completion (“D&C”) costs are shown gross of our working interest’s proportionate share. |
The following table provides operational data as of March 1, 2015 related to the 78 gross (74 net) Marcellus producing wells as of December 31, 2014.
| | | | | | | | | | | | | | | | |
| | | | | | | Periodic Flow Rates (MMcfe/d) | | | |
Year(s) | | Gross Operated
Wells Turned
Into Sales | | Average
Lateral Length
(Feet) | | 0-90 | | 91-180 | | 181-360 | | 361-720 | | D&C
($/Foot)(1) | |
| 2010-2011 | | 6 | | 3,281 | | 5.7 | | 6.0 | | 4.4 | | 2.7 | | $ | 2,377 | |
| 2012 | | 9 | | 5,731 | | 9.2 | | 10.0 | | 6.8 | | 4.2 | | | 1,660 | |
| 2013 | | 22 | | 6,286 | | 11.2 | | 10.6 | | 7.6 | | 5.9 | | | 1,476 | |
| 2014(2) | | 41 | | 7,282 | | 11.4 | | 10.3 | | 5.8 | | N/A | | | 1,176 | |
| | | | | | | | | | | | | | | | |
| Total(3) | | 78 | | 6,515 | | 10.5 | | 9.9 | | 6.8 | | 3.8 | | $ | 1,409 | |
| (1) | Drilling and completion (“D&C”) costs are shown gross of our working interest’s proportionate share. |
| (2) | Excludes seven producing wells acquired in our Greene County Acquisition in August 2014. |
| (3) | With the exception of wells turned into sales, totals represent averages weighted by number of wells. |
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Substantially all of our Marcellus development is located in Washington and Greene counties, Pennsylvania, where we control 86,000 net acres and have 495 drilling locations as of December 31, 2014.
Utica Shale
Our first Utica well, the Bigfoot 9H (6,950 foot lateral, 93% working interest), has been producing since June 2014. At the beginning of December 2014, we increased the flow rate from 14 MMcf/d to 15.5 MMcfe/d. This well has cumulatively produced approximately 3.7 Bcfe through February 2015.
Our second and third Utica wells, the Blue Thunder 10H and 12H (average 9,000 foot lateral, 67% working interest) have been online since September 2014. Each of these wells are currently producing approximately 16 MMcf/d and have each cumulatively produced approximately 2.5 Bcfe through February 2015.
In February 2015, we turned online two Utica wells (average 9,050 foot lateral, 56% working interest). Each of these wells is currently producing approximately 16 MMcf/d under our restricted choke program with flowing casing pressures of approximately 6,000 psi. Furthermore, we are currently completing six Utica wells (average 10,779 foot lateral, 54% working interest), three of which are expected to be turned to sales in spring 2015 and the remainder of which are expected to be turned to sales in summer 2015. Substantially all of our approximately 55,000 net acres are located in Belmont County, the focus of our operated Utica development, and we have 356 net risked drilling locations as of December 31, 2014.
At year-end 2014, we had a non-operated working interest in 20 gross (5 net) producing Utica wells, including interests in 17 gross (5 net) wells operated by Gulfport Energy in Belmont County, Ohio and 3 gross (1 net) wells operated by American Energy Utica in Guernsey County, Ohio.
In March 2015, we spud our first Utica well in Pennsylvania. This well is located in western Greene County and will be drilled to 12,700 feet total vertical depth with a 6,000 foot lateral. We anticipate first production during fourth quarter of 2015.
Firm Transportation and Realized Gas Pricing
Our firm transportation and firm sales portfolio supports our anticipated production growth by providing access to premium gas markets across the United States, including the Gulf Coast region, while reducing our pricing exposure to less than favorable local Appalachian markets. Approximately 73% of our fourth quarter production received TETCO M2 and Dominion South pricing, while the remaining production received favorable Gulf Coast and TCO pricing. In 2015, we anticipate that approximately 65% of our production will be transported to these premium gas markets, including Midwest markets.
The following tables provide basis exposure as a percentage of our production and average differentials to NYMEX for actual results through December 31, 2014 and estimated results for first quarter 2015 and full year 2015 and 2016.
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| | | | | | | | | | | | | | | | |
| | | Basis Exposure | |
| | | Actual | | | Estimated | |
| | | 4Q14 | | | 1Q15 | | | Full Year
2015 | | | Full Year
2016 | |
Basis | | | | | | | | | | | | | | | | |
Gulf Coast | | | 2 | % | | | 35 | % | | | 40 | % | | | 46 | % |
TCO | | | 25 | % | | | 21 | % | | | 17 | % | | | 8 | % |
TETCO M2 | | | 37 | % | | | 14 | % | | | 11 | % | | | 10 | % |
Dominion South | | | 36 | % | | | 30 | % | | | 23 | % | | | 24 | % |
Midwest and Ontario | | | — | % | | | — | % | | | 9 | % | | | 12 | % |
| | | | | | | | | | | | | | | | |
| | | Realized Price | |
| | | Actual | | | Estimated(1) | |
| | | 4Q14 | | | 1Q15 | | | Full Year
2015 | | | Full Year
2016 | |
NYMEX Henry Hub price ($/MMBtu) | | $ | 3.78 | | | $ | 2.85 | | | $ | 2.88 | | | $ | 3.19 | |
Average basis impact ($/MMBtu) | | | (0.93 | ) | | | (0.40 | ) | | | (0.42 | ) | | | (0.46 | ) |
Btu uplift (MMBtu/Mcf) | | | 0.15 | | | | 0.13 | | | | 0.12 | | | | 0.14 | |
| | | | | | | | | | | | | | | | |
Pre-hedge realized price ($/Mcf) | | | 3.00 | | | | 2.58 | | | | 2.58 | | | | 2.87 | |
Realized hedging gain (loss) ($/Mcf) | | | 0.06 | | | | 0.75 | | | | 0.87 | | | | 0.33 | |
| | | | | | | | | | | | | | | | |
Post-hedge realized price ($/Mcf) | | | 3.06 | | | | 3.33 | | | | 3.45 | | | | 3.20 | |
Net firm transportation sales | | | 0.40 | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
Adjusted realized price ($/Mcf) | | $ | 3.46 | | | $ | 3.33 | | | $ | 3.45 | | | $ | 3.20 | |
| | | | | | | | | | | | | | | | |
| (1) | NYMEX price as of 2/27/15. |
Financial Position and Liquidity
As of December 31, 2014, our upstream liquidity position of $712 million consisted of $483 million available under our senior secured revolving credit facility and $229 million of cash on hand(1). This liquidity is expected to be sufficient to completely fund our 2015 drilling and completion and leasehold budget. In addition, our 2015 retained midstream development is expected to be funded entirely with our recently structured $300 million midstream revolver.
Commodity Hedging Update
The weighted average floor price of our 405 BBtu/d 2015 hedge portfolio, including our basis swaps, is $3.50 per MMBtu, representing 84% of our 2015 expected production, based on the midpoint of our previously announced production guidance. Please see the “Derivatives Information” table at the end of this press release for more detailed information about our derivatives positions.
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Midstream Segment
Average daily throughput for the fourth quarter 2014 was 591 MDth/d consisting of 10% third party volumes.
Rice Midstream Partners LP (NYSE: RMP)
Pennsylvania Gathering System
Average daily throughput for the fourth quarter 2014 was 517 MDth/d consisting of 9% third party volumes.
| | | | | | | | | | | | |
| 2014 Operational Results | | Three Months Ended
December 31, 2014 | | | As of December 31, 2014 | |
| | | Average Daily
Throughput (MDth/d) | | | Pipeline (miles) | | | Capacity (MDth/d) | |
Washington County System | | | 351 | | | | 71 | | | | 2,772 | |
Greene County System | | | 166 | | | | 10 | | | | 420 | |
| | | | | | | | | | | | |
Total | | | 517 | | | | 81 | | | | 3,192 | |
On December 22, 2014, RMP closed its initial public offering of 28,750,000 common units representing limited partner interests at a price to the public of $16.50 per common unit. Rice Energy and the public unitholders each own an approximate 50% limited partner interest in RMP. As of December 31, 2014, RMP’s liquidity position of $477 million consisted of $450 million available under its senior secured revolving credit facility and $27 million of cash on hand.
On January 30, 2015, RMP declared its initial quarterly distribution of $0.0204 per unit for the fourth quarter 2014. The distribution, based upon the 10-day period following the closing of its initial public offering on December 22, 2014 through December 31, 2014, represents a prorated minimum quarterly distribution of $0.1875 per unit ($0.75 per unit annualized).
Rice Midstream Holdings
Ohio Gathering System
Average daily throughput for the fourth quarter 2014 was 74 MDth/d consisting of 34% third party volumes.
| | | | | | | | | | | | |
| 2014 Operational Results | | Three Months Ended
December 31, 2014 | | | As of December 31, 2014 | |
| | | Average Daily
Throughput (MDth/d) | | | Pipeline (miles) | | | Capacity (MDth/d) | |
Belmont County System | | | 74 | | | | 21 | | | | 525 | |
During the fourth quarter, we completed construction of an additional 17 miles of high pressure gathering lines, enabling us to gather new third party volumes in Ohio. Construction of our Ohio gathering system continues, which is expected to provide total throughput capacity of 2.6 MMdth/d by year end 2015.
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Fresh Water Distribution Systems
Construction of our fresh water distribution systems is in progress and by year end 2015 will provide direct access to 9.2 MMGPD of fresh water from the Monongahela River and other regional water sources in Pennsylvania and 16.7 MMGPD of fresh water from the Ohio River and several other regional sources in Ohio for our well completion operations.
Conference Call
Rice Energy will host a conference call on March 12, 2015 at 9:00 a.m. Eastern time (8:00 a.m. Central time) to discuss fourth quarter and full year 2014 financial and operating results. To listen to a live audio webcast of the conference call, please visit Rice Energy’s website atwww.riceenergy.com. A replay of the conference call will be available for two weeks and can also be accessed from our homepage.
An updated company presentation is available for download our website (www.riceenergy.com).
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 atwww.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 in this release, 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, 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; 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; and the timing of development expenditures. 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
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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.
Contact:
Julie Danvers, Director of Investor Relations
(832) 708-3437
Julie.Danvers@RiceEnergy.com
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Rice Energy Inc.
Condensed Consolidated Statement of Operations
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended
December 31, | | | Year Ended
December 31, | |
| (in thousands, except per share data) | | 2014 | | | 2013 | | | 2014 | | | 2013 | |
Natural gas production (MMcf) | | | 36,076 | | | | 7,268 | | | | 97,172 | | | | 22,995 | |
Oil and NGL production (MBbls) | | | 90,836 | | | | — | | | | 94 | | | | — | |
Total production (MMcfe) | | | 36,621 | | | | 7,268 | | | | 97,737 | | | | 22,995 | |
| | | | |
Operating revenues: | | | | | | | | | | | | | | | | |
Natural gas, oil and NGL sales | | $ | 112,385 | | | $ | 27,628 | | | $ | 359,201 | | | $ | 87,847 | |
Firm transportation sales, net | | | 14,386 | | | | — | | | | 26,237 | | | | — | |
Other revenue | | | 2,627 | | | | 260 | | | | 5,504 | | | | 840 | |
| | | | | | | | | | | | | | | | |
Total operating revenues | | | 129,398 | | | | 27,888 | | | | 390,942 | | | | 88,687 | |
| | | | |
Operating expenses: | | | | | | | | | | | | | | | | |
Lease operating | | | 8,565 | | | | 2,514 | | | | 24,971 | | | | 8,309 | |
Gathering, compression and transportation | | | 14,321 | | | | 2,823 | | | | 40,225 | | | | 9,774 | |
Production taxes and impact fees | | | 2,024 | | | | 600 | | | | 4,647 | | | | 1,629 | |
Exploration | | | 2,519 | | | | 8,167 | | | | 4,225 | | | | 9,951 | |
Incentive unit expense | | | 4,266 | | | | — | | | | 105,961 | | | | — | |
Restricted unit expense | | | — | | | | (7,181 | ) | | | — | | | | 32,906 | |
Stock compensation expense | | | 2,279 | | | | — | | | | 5,553 | | | | — | |
General and administrative | | | 19,284 | | | | 7,001 | | | | 56,017 | | | | 16,953 | |
Depreciation, depletion and amortization | | | 64,358 | | | | 9,600 | | | | 156,270 | | | | 32,815 | |
Acquisition expense | | | 92 | | | | — | | | | 2,339 | | | | — | |
Amortization of intangible assets | | | 408 | | | | — | | | | 1,156 | | | | — | |
Loss from sale of interest in gas properties | | | — | | | | 4,230 | | | | — | | | | 4,230 | |
| | | | | | | | | | | | | | | | |
Total operating expenses | | | 118,116 | | | | 27,754 | | | | 401,364 | | | | 116,567 | |
| | | | | | | | | | | | | | | | |
Operating loss | | | 11,282 | | | | 134 | | | | (10,422 | ) | | | (27,880 | ) |
Interest expense | | | (11,454 | ) | | | (4,882 | ) | | | (50,191 | ) | | | (17,915 | ) |
Gain on purchase of Marcellus joint venture | | | — | | | | — | | | | 203,579 | | | | — | |
Other income (loss) | | | 713 | | | | (94 | ) | | | 893 | | | | (440 | ) |
Gain (loss) on derivative instruments | | | 181,120 | | | | (9,807 | ) | | | 186,477 | | | | 6,891 | |
Amortization of deferred financing costs | | | (766 | ) | | | (469 | ) | | | (2,495 | ) | | | (5,230 | ) |
Loss on extinguishment of debt | | | (3,720 | ) | | | — | | | | (7,654 | ) | | | (10,622 | ) |
Write-off of deferred financing costs | | | — | | | | — | | | | (6,896 | ) | | | — | |
Equity in income (loss) of joint ventures | | | — | | | | 122 | | | | (2,656 | ) | | | 19,420 | |
| | | | | | | | | | | | | | | | |
Income (loss) before income taxes | | | 177,175 | | | | (14,996 | ) | | | 310,635 | | | | (35,776 | ) |
Income tax expense | | | (72,813 | ) | | | — | | | | (91,600 | ) | | | — | |
| | | | | | | | | | | | | | | | |
Net income (loss) | | | 104,362 | | | | (14,996 | ) | | | 219,035 | | | | (35,776 | ) |
Less: Net income attributable to noncontrolling interests | | | (581 | ) | | | — | | | | (581 | ) | | | — | |
| | | | | | | | | | | | | | | | |
Net income (loss) attributable to Rice Energy Inc. | | $ | 103,781 | | | $ | (14,996 | ) | | $ | 218,454 | | | $ | (35,776 | ) |
| | | | | | | | | | | | | | | | |
| | | | |
Adjusted EBITDAX(1) | | $ | 87,335 | | | $ | 8,896 | | | $ | 246,610 | | | $ | 47,352 | |
| | | | |
Weighted average shares-basic | | | 136,280,766 | | | | 88,000,000 | | | | 128,151,171 | | | | 80,441,905 | |
Weighted average shares-diluted | | | 136,352,435 | | | | 88,000,000 | | | | 128,225,155 | | | | 80,441,905 | |
| | | | |
Earnings (loss) per share—basic | | $ | 0.76 | | | $ | (0.17 | ) | | $ | 1.70 | | | $ | (0.44 | ) |
Earnings (loss) per share—diluted | | $ | 0.76 | | | $ | (0.17 | ) | | $ | 1.70 | | | $ | (0.44 | ) |
| (1) | Please see “Supplemental Non-GAAP Financial Measures” for a description of Adjusted EBITDAX. |
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Rice Energy Inc.
Supplemental Non-GAAP Financial Measures
(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 or interest income; income taxes; write-down of abandoned leases; depreciation, depletion and amortization; amortization of deferred financing costs; amortization of intangible assets; equity in (income) loss of our joint ventures; derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash stock compensation expense; (gain) loss from sale of interest in gas properties; (gain) loss on acquisition; acquisition expenses; (gain) loss on extinguishment of debt; write-off of deferred financing costs; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.
The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).
| | | | | | | | |
| (in thousands) | | Three Months Ended
December 31, 2014 | | | Year Ended
December 31, 2014 | |
Adjusted EBITDAX reconciliation to net income (loss): | | | | | | | | |
Net income (loss) | | $ | 104,362 | | | $ | 219,035 | |
Interest expense | | | 11,454 | | | | 50,191 | |
Depreciation, depletion and amortization | | | 64,358 | | | | 156,270 | |
Amortization of deferred financing costs | | | 766 | | | | 2,495 | |
Amortization of intangible assets | | | 408 | | | | 1,156 | |
Equity in loss of joint ventures | | | — | | | | 2,656 | |
Gain on derivative instruments(1) | | | (181,120 | ) | | | (186,477 | ) |
Net cash receipts on settled derivative instruments(1) | | | 1,999 | | | | (18,784 | ) |
Gain on purchase of Marcellus joint venture(2) | | | — | | | | (203,579 | ) |
Acquisition expense | | | 92 | | | | 2,339 | |
Non-cash stock compensation expense | | | 2,279 | | | | 5,553 | |
Non-cash incentive unit expense | | | 4,266 | | | | 105,961 | |
Income tax expense | | | 72,813 | | | | 91,600 | |
Loss on extinguishment of debt | | | 3,720 | | | | 7,654 | |
Write-off of deferred financing costs | | | — | | | | 6,896 | |
Exploration expenses | | | 2,519 | | | | 4,225 | |
Noncontrolling interest | | | (581 | ) | | | (581 | ) |
| | | | | | | | |
Adjusted EBITDAX | | $ | 87,335 | | | $ | 246,610 | |
| | | | | | | | |
| (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) | Represents gain incurred on the purchase of the remaining 50% interest in our Marcellus joint venture. |
10
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 non-controlling interest, derivative fair value (gain) loss, excluding net cash receipts on settled derivative instruments; non-cash stock compensation expense; (gain) loss from sale of interest in gas properties; (gain) loss on acquisition; acquisition expenses; (gain) loss on extinguishment of debt; and write-off of deferred financing costs. Adjusted net income (loss) is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.
The following table presents a reconciliation of the non-GAAP financial measure of adjusted net income to the GAAP financial measure of net income (loss).
| | | | | | | | |
| (in thousands) | | Three Months Ended
December 31, 2014 | | | Year Ended
December 31, 2014 | |
Reconciliation to net income (loss): | | | | | | | | |
Net income (loss) | | $ | 104,362 | | | | $218,454 | |
Gain on derivative instruments, net of tax(1) | | | (106,686 | ) | | | (109,820) | |
Net cash receipts on settled derivative instruments, net of tax(1) | | | 1,177 | | | | (11,062 ) | |
Incentive unit expense, net of tax | | | 2,513 | | | | 62,403 | |
Gain on purchase of Marcellus joint venture(2) | | | — | | | | (203,579 ) | |
Acquisition expense, net of tax | | | 54 | | | | 1,377 | |
Loss on extinguishment of debt, net of tax | | | 2,191 | | | | 4,508 | |
Write-off of deferred financing costs, net of tax | | | — | | | | 4,061 | |
| | | | | | | | |
Adjusted net income (loss) | | $ | 3,612 | | | $ | (33,659 | ) |
| | | | | | | | |
| (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. |
| (2) | Represents gain incurred on the purchase of the remaining 50% interest in our Marcellus joint venture. |
11
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 to the standardized measure of discounted future net cash flows:
| | | | | | | | |
| | | Year Ended December 31, | |
| (in millions) | | 2014 | | | 2013 | |
Reconciliation to PV-10: | | | | | | | | |
Standardized measure of discounted future net cash flows | | $ | 1,308 | | | $ | 444 | |
Discounted future net cash flows for income taxes | | | 436 | | | | 265 | |
| | | | | | | | |
Discounted future net cash flows before income taxes (PV-10) | | $ | 1,744 | | | $ | 709 | |
| | | | | | | | |
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Rice Energy Inc.
Derivatives Information
(Unaudited)
The table below provides data associated with our derivatives as of March 12, 2015 for the periods indicated:
| | | | | | | | | | | | |
All-In Fixed Price Derivatives | | 2015 | | | 2016 | | | 2017 | |
NYMEX Natural Gas Swaps: | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 166 | | | | 214 | | | | 60 | |
Weighted Average Swap Price ($/MMBtu) | | $ | 4.09 | | | $ | 4.14 | | | $ | 4.24 | |
| | | |
NYMEX Natural Gas Collars: | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 139 | | | | — | | | | — | |
Weighted Average Floor Price ($/MMBtu) | | $ | 3.96 | | | $ | — | | | $ | — | |
Weighted Average Collor Price ($/MMBtu) | | $ | 4.65 | | | $ | — | | | $ | — | |
NYMEX Volume Hedged (BBtu/d) | | | 305 | | | | 214 | | | | 60 | |
Swap + Collar Floor ($/MMBtu) | | $ | 4.03 | | | $ | 4.14 | | | $ | 4.24 | |
| | | |
Dominion Natural Gas Swaps | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 71 | | | | 31 | | | | — | |
Weighted Average Swap Price ($/MMBtu) | | $ | 2.53 | | | $ | 2.62 | | | $ | — | |
| | | |
TCO Natural Gas Swaps | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 29 | | | | — | | | | — | |
Weighted Average Swap Price ($/MMBtu) | | $ | 3.30 | | | $ | — | | | $ | — | |
| | | |
Total Fixed Price Derivatives | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 405 | | | | 245 | | | | 60 | |
Weighted Average Swap Price ($/MMBtu) | | $ | 3.71 | | | $ | 3.95 | | | $ | 4.24 | |
| | | |
Differential to NYMEX Henry Hub Contract Summary | | 2015 | | | 2016 | | | 2017 | |
TCO Basis Swaps | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 37 | | | | 17 | | | | — | |
Weighted Average Swap Price ($/MMBtu) | | $ | (0.42 | ) | | $ | (0.42 | ) | | $ | — | |
| | | |
Dominion Basis Swaps | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 14 | | | | — | | | | — | |
Weighted Average Swap Price ($/MMBtu) | | $ | (1.12 | ) | | $ | — | | | $ | — | |
| | | |
M2 Basis Swaps | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 24 | | | | — | | | | — | |
Weighted Average Swap Price ($/MMBtu) | | $ | (0.94 | ) | | $ | — | | | $ | — | |
| | | |
ELA Basis Swaps | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 23 | | | | — | | | | — | |
Weighted Average Swap Price ($/MMBtu) | | $ | (0.13 | ) | | $ | — | | | $ | — | |
| | | |
Appalachian Fixed Basis (Physical) | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 25 | | | | 21 | | | | — | |
Weighted Average Swap Price ($/MMBtu) | | $ | (0.79 | ) | | $ | (0.79 | ) | | $ | — | |
| | | |
Gulf Coast Fixed Basis (Physical) | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 73 | | | | 100 | | | | 92 | |
Weighted Average Swap Price ($/MMBtu) | | $ | (0.17 | ) | | $ | (0.17 | ) | | $ | (0.17 | ) |
| | | |
Total Basis Swaps (Financial+Physical) | | | | | | | | | | | | |
Volume Hedged (BBtu/d) | | | 195 | | | | 138 | | | | 92 | |
Weighted Average Swap Price ($/MMBtu) | | $ | (0.45 | ) | | $ | (0.29 | ) | | $ | (0.17 | ) |
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The table below provides supplemental balance sheet data as of December 31, 2014.
| | | | |
| Supplemental Balance Sheet data (in thousands) | | As of December 31, 2014 | |
Cash and cash equivalents | | $ | 256,130 | |
Long-term debt | | | | |
Revolving credit facilities | | | — | |
6.25% Senior notes due April 2022 | | | 900,000 | |
Total debt | | | 900,000 | |
| | | | |
Net debt | | $ | 643,870 | |
| | | | |
The table below outlines our firm transportation capacity by pipeline for the projects to which we are committed as anchor shipper.
| | | | | | | | | | |
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 | | June-15 | | 175,000 | | 20 Yrs | | Midwest/Gulf Coast |
| Union Town to Gas City | | TETCO | | Nov-15 | | 86,500 | | 10 Yrs | | Midwest/Gulf Coast |
| OPEN | | TETCO | | Nov-15 | | 50,000 | | 20 Yrs | | Gulf Coast |
| ET Rover | | Rover | | July-17 | | 100,000 | | 15 Yrs | | Canada |
| Access South | | TETCO | | Nov-17 | | 320,000 | | 25 Yrs | | Gulf Coast |
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