Item 1. Business
The estimated proved reserve information for the properties of each of us and our Marcellus joint venture contained in this Annual Report are based on reserve reports relating thereto prepared by the independent petroleum engineers of Netherland Sewell & Associates Inc. (“NSAI”). We refer to these reports collectively as our “reserve reports.”
Our Company
We are an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. We are focused on creating shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We strive to be an early entrant into the core of a shale play by identifying what we believe to be the core of the play and aggressively executing our acquisition strategy to establish a largely contiguous acreage position. We believe we were an early identifier of the core of both the Marcellus Shale in southwestern Pennsylvania and the Utica Shale in southeastern Ohio.
All of our current and planned development is located in what we believe to be the core of the Marcellus and Utica Shales. As of December 31, 2013, we held approximately 43,351 pro forma net acres in the southwestern core of the Marcellus Shale, primarily in Washington County, Pennsylvania. We established our Marcellus Shale acreage position through a combination of largely contiguous acreage acquisitions in 2009 and 2010 and through numerous bolt-on acreage acquisitions. In 2012, we acquired approximately 33,499 of our 46,488 net acres in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be the core of the Utica Shale based on publicly available drilling results. We operate a substantial majority of our acreage in the Marcellus Shale and a majority of our acreage in the Utica Shale.
Since completing our first horizontal well in the fourth quarter of 2010, our pro forma average net daily production has grown approximately 77 times to 154 MMcf/d for the fourth quarter of 2013. All of our production to date has been dry gas attributable to our operations in the Marcellus Shale. Prior to the second quarter of 2013, we ran a two-rig drilling program focused on delineating and defining the boundaries of our Marcellus Shale acreage position. In the second quarter of 2013, we shifted our operational focus from exploration to development, commencing a four-rig drilling program consisting of two rigs specifically for drilling the tophole sections of our horizontal wells and two rigs specifically for drilling the curve and lateral sections of our horizontal wells. We expect to continue running this four-rig program in the Marcellus Shale through 2014. The following chart shows our pro forma average net daily production for each quarter since completing our first horizontal well in the Marcellus Shale.
We have drilled and completed 37 pro forma horizontal Marcellus wells as of December 31, 2013 with a 100% success rate (defined as the rate at which wells are completed and produce in commercially viable quantities). As of December 31, 2013, we had 349 gross (325 net) pro forma identified drilling locations in the Marcellus Shale. Additionally, we have drilled and completed three Upper Devonian horizontal wells on our Marcellus Shale acreage with a 100% success rate. Based on our Upper Devonian wells and those of other operators in the vicinity of our acreage as well as other geologic data, we estimate that substantially all of our Marcellus Shale acreage in Southwestern Pennsylvania is prospective for the slightly shallower Upper Devonian Shale. As of December 31, 2013, we had 211 gross (194 net) pro forma identified drilling locations in the Upper Devonian Shale.
For the Utica Shale, we applied the same shale analysis and acquisition strategy that we developed and employed in the Marcellus Shale to acquire our acreage. We began to delineate our Utica Shale leasehold position with the spudding of our first well in Belmont County in October 2013. Our delineation operations are being conducted with a two-rig drilling program (one tophole rig and one horizontal rig), initially sourced from our Marcellus Shale rigs, which were replaced in early 2014 with two new Marcellus Shale rigs. We intend to maintain this two-rig drilling program in the Utica Shale through 2014. In 2015, we intend to transition to a primarily development-focused strategy in the Utica Shale. As of December 31, 2013, we had 753 gross (233 net) identified drilling locations in the Utica Shale.
As of December 31, 2013, our pro forma estimated proved reserves were 602 Bcf, all of which were in southwestern Pennsylvania, with 42% proved developed and 100% natural gas. In 2014, excluding $100 million cash paid with respect to the Marcellus JV Buy-In and approximately $110 million expected to be paid with respect to the Momentum Acquisition, each as described in “-Our Properties-Recent Developments,” we plan to invest $1,230.0 million in our operations as follows:
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$430.0 million for drilling and completion in the Marcellus Shale;
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$150.0 million for drilling and completion in the Utica Shale;
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$385.0 million for leasehold acquisitions; and
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$265.0 million for midstream infrastructure development.
This represents a 96% increase over our $629.0 million pro forma 2013 capital expenditures. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The following table provides a summary of our pro forma acreage, average working interest, producing wells and drilling locations as of December 31, 2013, projected 2014 gross wells drilled and projected 2014 drilling and completion capital budget as of March 21, 2014 and our average net daily production for the three months ended December 31, 2013:
(1)
Based on our reserve reports as of December 31, 2013, we had 44 gross (39 net) locations in the Marcellus Shale associated with proved undeveloped reserves and 13 gross (12 net) locations in the Marcellus Shale associated with proved developed not producing reserves. Please see “-Our Operations-Reserve Data-Determination of Identified Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Item 1A.
Item 1A. Risk Factors
Investing in our common stock involves risks. You should carefully consider the information in this Annual Report, including the matters addressed under “Cautionary Statement Regarding Forward-Looking Statements,” and the following risks before making an investment decision. The trading price of our common stock could decline due to any of these risks, and you may lose all or part of your investment.
Risks Related to Our Business
Natural gas, NGL and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our natural gas production heavily influence, and to the extent we produce oil and NGLs in the future, the prices we receive for oil and NGL production will heavily influence, our revenue, operating results profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas, NGLs and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
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worldwide and regional economic conditions affecting the global supply of and demand for natural gas, NGLs and oil;
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the price and quantity of imports of foreign natural gas, including liquefied natural gas;
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political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;
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the level of global exploration and production;
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the level of global inventories;
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prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;
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the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;
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localized and global supply and demand fundamentals and transportation availability;
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weather conditions and natural disasters;
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technological advances affecting energy consumption;
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the cost of exploring for, developing, producing and transporting reserves;
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speculative trading in natural gas and crude oil derivative contracts;
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risks associated with operating drilling rigs;
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the price and availability of competitors’ supplies of natural gas and oil and alternative fuels; and
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domestic, local and foreign governmental regulation and taxes.
Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity and recession in parts of the world. This has reduced worldwide demand for energy and resulted in lower natural gas, NGL and oil prices.
In addition, substantially all of our natural gas production is sold to purchasers under contracts with market-based prices based on New York Mercantile Exchange (“NYMEX”) Henry Hub prices. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differentials, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. We may experience differentials to NYMEX Henry Hub prices in the future, which may be material.
Lower commodity prices and negative increases in our differentials will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically.
If commodity prices further decrease or our negative differentials further increase, a significant portion of our development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices or an increase in our negative differentials may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.
Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves.
The natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas reserves. In 2014, excluding $100.0 million cash paid with respect to the Marcellus JV Buy-In and approximately $110.0 million expected to be paid with respect to the Momentum Acquisition, we plan to invest $1,230.0 million in our operations, including $430.0 million for drilling and completion in the Marcellus Shale, $150.0 million for drilling and completion in the Utica Shale, $385.0 million for leasehold acquisitions and $265.0 million for midstream infrastructure development. Our capital budget excludes acquisitions, other than leasehold acquisitions. We expect to fund our 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and a portion of the net proceeds of our IPO. Our 2014 capital expenditure budget also assumes that the borrowing base under our revolving credit facility is increased during 2014. If our lenders do not increase our borrowing base, we may seek alternate debt financing or reduce our capital expenditures. In addition, a portion of our 2014 capital budget is projected to be financed with cash flows from operations derived from wells drilled on drilling locations not associated with proved reserves in our reserve reports. The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in natural gas prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facility; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.
Our cash flow from operations and access to capital are subject to a number of variables, including:
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our proved reserves;
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the level of hydrocarbons we are able to produce from existing wells;
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our access to, and the cost of accessing end markets for our production;
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the prices at which our production is sold;
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our ability to acquire, locate and produce new reserves;
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the levels of our operating expenses; and
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our ability to borrow under our revolving credit facility.
If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling, including or as a result of the application of these techniques, include, but are not limited to, the following:
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effectively controlling the level of pressure flowing from particular wells;
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landing our wellbore in the desired drilling zone;
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staying in the desired drilling zone while drilling horizontally through the formation;
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running our casing the entire length of the wellbore; and
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being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells, including or as a result of the application of these techniques, include, but are not limited to, the following:
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the ability to fracture stimulate the planned number of stages;
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the ability to run tools the entire length of the wellbore during completion operations; and
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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
Drilling for and producing natural gas are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in such wells or that various characteristics of the well will cause us to plug or abandon the well prior to producing in commercially viable quantities.
Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “-Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
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delays imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal, discharge of greenhouse gases, and limitations on hydraulic fracturing;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;
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equipment failures, accidents or other unexpected operational events;
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lack of available gathering facilities or delays in construction of gathering facilities;
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lack of available capacity on interconnecting transmission pipelines;
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adverse weather conditions, such as blizzards and ice storms;
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issues related to compliance with environmental regulations;
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environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
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declines in natural gas prices;
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limited availability of financing at acceptable terms;
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title problems; and
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limitations in the market for natural gas.
Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.
We have incurred losses from operations for various periods since our inception and may do so in the future.
We incurred a net loss of $35.8 million and $19.3 million for the year ended December 31, 2013 and 2012, respectively. Our development of and participation in an increasingly larger number of prospects has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire natural gas reserves. As a result, we may not be able to sustain profitability or positive cash flows from operating activities in the future, which could adversely affect the trading price of our common stock.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.
Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our $1.5 billion first lien secured revolving credit facility (as amended from $500.0 million, effective January 29, 2014) and our $300.0 million second lien secured term loan, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
As of March 20, 2014, the borrowing base under our $1.5 billion revolving credit facility was $350.0 million (as amended from $500.0 million and $200.0 million, respectively, effective January 29, 2014). Our next scheduled borrowing base redetermination is expected to occur in April 2014. In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.
Our producing properties are geographically concentrated in the Marcellus Shale and Upper Devonian Shale formations in Washington and Greene Counties, Pennsylvania. As of December 31, 2013 and 2012, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by
governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs and changes in regional and local political regimes and regulations. Such conditions could have a material adverse effect on our financial condition and results of operations.
In addition, a number of areas within the Marcellus Shale and Utica Shale have historically been subject to mining operations. For example, third parties may engage in subsurface mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling or adversely impact our midstream activities or those on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins, the plugging and abandonment of any of our wells or the repair of our midstream facilities. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. In connection with entering into the Marcellus JV Buy-In, we agreed to continue to acknowledge the dominance of mining by Alpha Natural Resources, Inc. within the area of mutual interest of our Marcellus joint venture. As such, in addition to coordinating with Alpha Holdings on, and in certain circumstances obtaining the prior approval of Alpha Holdings for, future drilling operations, we may also be required to take steps to assure the dominance of the mining operations of Alpha Natural Resources, Inc., including the plugging and abandonment of wells at the direction of Alpha Holdings upon two years notice. These restrictions on our operations, and any similar restrictions, can cause delays or interruptions or can prevent us from executing our business strategy, which could have a material adverse effect on our financial condition and results of operations.
Due to the concentrated nature of our portfolio of natural gas properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
We completed our first horizontal well in the Marcellus Shale in October 2010 and began to delineate our Utica Shale leasehold position in October 2013. While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in these areas are more uncertain than drilling results in areas that are more developed and have a longer history of established production. Since new or emerging plays have limited or no production history and since we have no experience drilling in these plays (including the Utica Shale), we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful. Additionally, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. For example, as a result of unexpected levels of pressure, in December 2013 we plugged and abandoned the first well we spud in the Utica Shale. We have since spud our second well in the Utica Shale and expect to obtain an initial production test from this well in the second quarter of 2014. We cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such unproved property or wells.
During the term of the Utica Development Agreements, we will rely on Gulfport for the success of our project in the Southern Contract Area in Belmont County, Ohio, and we may not be able to maximize the value of our properties in the Southern Contract Area as we deem best because we are not in full control of this project.
During the term of the Utica Development Agreements, the success of our operation in the Southern Contract Area in Belmont County, Ohio, will depend in part on the ability of Gulfport to effectively exploit the acreage it operates under the Development Agreement. Please read “Item 1. Business-Our Properties-Utica Shale-Development Agreement and Area of Mutual Interest Agreement.” Pursuant to the Development Agreement, we have designated Gulfport as the operator of our existing and future acreage in the Southern Contract Area. A failure or inability of Gulfport to adequately exploit the acreage it operates would have a significant impact on our results of operations. In addition, other than limitations set forth in the terms of the Development Agreement, we do not control the amount of capital that Gulfport may require for development of properties in the Southern Contract Area. Accordingly, we may be required to allocate capital to development of the Southern Contract Area at times when we otherwise would allocate capital to the Northern Contract Area, our Marcellus Shale acreage or elsewhere or otherwise be forced to terminate the Utica Development Agreements. Under any of these circumstances, our prospects for realization of the potential value of the oil, natural gas and NGL reserves associated with the Southern Contract Area could be adversely affected. Our lack of control may limit our ability to develop our properties in the manner we believe to be in our best interest.
Insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices.
The Appalachian Basin natural gas business environment has historically been characterized by periods in which production has surpassed local takeaway capacity, resulting in substantial discounts in the price received by producers such as us. Although additional Appalachian Basin takeaway capacity was added in 2013 and 2012, we do not believe the existing and expected capacity will be sufficient to keep pace with the increased production caused by accelerated drilling in the area. We expect that a significant portion of our production from the Utica Shale will be transported on pipelines that experience a differential to NYMEX Henry Hub prices. If we are unable to complete the Momentum Acquisition or unable to secure additional gathering and compression capacity and long-term firm takeaway capacity on major pipelines that are in existence or under construction in our core operating area to accommodate our growing production and to manage basis differentials, it could have a material adverse effect on our financial condition and results of operations.
We are required to pay fees to our service providers based on minimum volumes regardless of actual volume throughput.
We have various gas transportation service agreements in place, each with minimum volume delivery commitments. As of March 1, 2014, our average annual contractual firm transportation and firm sales obligations for 2014, 2015 and 2016 were approximately 330,000 MMBtu/d, 654,000 MMBtu/d, and 761,000 MMBtu/d, respectively, which are in excess of our pro forma average daily gross operated production of approximately 231,000 MMBtu/d for December 2013. While we believe that our future natural gas volumes will be sufficient to satisfy the minimum requirements under our gas transportation services agreements based on our current production and our exploration and development plan, we can provide no such assurances that such volumes will be sufficient. We are obligated to pay fees on minimum volumes to our service providers regardless of actual volume throughput, which could be significant. If these fees on minimum volumes are substantial, we may not be able to generate sufficient cash to cover these obligations, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
Our revolving credit facility and second lien term loan each contain a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:
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sell assets;
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make loans to others;
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make investments;
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enter into mergers;
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make certain payments;
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hedge future production or interest rates;
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incur liens;
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engage in certain other transactions without the prior consent of the lenders; and
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pay dividends.
In addition, our credit facilities require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. On certain occasions in the past we have not met these financial covenants. Our convertible debentures also require us to maintain certain financial ratios that could limit our ability to incur additional indebtedness. These restrictions may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our credit facilities and our convertible debentures impose on us.
Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine on a semi-annual basis based upon projected revenues from the natural gas properties securing our loan. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. If the requisite number of lenders do not agree to an increase, then the borrowing base will be the lowest borrowing base acceptable to such lenders. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas properties as additional collateral after applicable grace periods. As of December 31, 2013, we did not have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under our revolving credit facility. As of March 20, 2014, the borrowing base under our revolving credit facility was $350.0 million (as amended from $200.0 million, effective January 29, 2014). Our next scheduled borrowing base redetermination is expected to occur in April 2014.
A breach of any covenant in either our revolving credit facility or our second lien term loan facility would result in a default under the applicable agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under the relevant facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
In certain circumstances we may have to purchase commodities on the open market or make cash payments under our hedging arrangements and these payments could be significant.
If our production is less than the volume commitments under our hedging arrangements, or if natural gas or oil prices exceed the price at which we have hedged our commodities, we may be obligated to make cash payments to our hedge counterparties or purchase the volume difference at market prices, which could, in certain circumstances, be significant. As of December 31, 2013, we had entered into hedging contracts through December 31, 2017 covering a total of approximately 186 Bcf of our projected natural gas production at a weighted average price of $4.09 per MMBtu. For the period from January 1, 2014 until December 31, 2014, we have hedged approximately 62.9 Bcf of our projected natural gas production at a weighted average price of $4.05 per MMBtu. If we have to purchase additional commodities on the open market or post cash collateral to meet our obligations under such arrangements, our cash otherwise available for use in our operations would be reduced.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.
In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. As a substantial portion of our reserve estimates are made without the benefit of a lengthy production history, any significant variance from the above assumption could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. Most of our producing wells have been operational for less than one year and estimated reserves vary substantially from well to well and are not directly correlated to perforated lateral length or completion
technique. Furthermore, the lack of operational history for horizontal wells in the Utica Shale may also contribute to the inaccuracy of future estimates of reserves and could result in our failing to achieve expected results in the play. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates or, in the case of the Utica Shale, management expectations, would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our gross identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our identified drilling locations.
Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to unitize such leaseholds with ours, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified.
As of December 31, 2013, we had 1,313 gross (752 net) pro forma identified drilling locations. As a result of the limitations described above, we may be unable to drill many of our identified drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified drilling locations, see “Item 1. Business-Our Operations-Reserve Data-Determination of Identified Drilling Locations.”
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In a highly competitive market for acreage, failure to drill sufficient wells to hold acreage may result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
Leases on our oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2013, on a pro forma basis, we had leases representing 1,054 undeveloped acres scheduled to expire in 2014, 2,365 undeveloped acres scheduled to expire in 2015, 4,132 undeveloped acres scheduled to expire in 2016, 35,639 undeveloped acres scheduled to expire in 2017 and 28,161 undeveloped acres scheduled to expire in 2018 and thereafter. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. Moreover, many of our leases require lessor consent to unitize, which may make it more difficult to hold our leases by production. Any reduction in our current drilling program, either through a reduction in capital expenditures or the unavailability of drilling rigs, could result in the loss of acreage through lease expirations. In addition, in order to hold our current leases scheduled to expire in 2014 and 2015, we will need to operate at least a one-rig program. We cannot assure you that we will have the liquidity to deploy rigs when needed, or that commodity prices will warrant operating such a drilling program. Our reserves and future production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage and the loss of any leases could materially and adversely affect our ability to so develop such acreage.
The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2013, 2012 and 2011, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:
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actual prices we receive for oil and natural gas;
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actual cost of development and production expenditures;
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the amount and timing of actual production; and
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changes in governmental regulations or taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. As a limited liability company, our predecessor was not subject to federal taxation. Accordingly, our standardized measure does not provide for federal corporate income taxes because taxable income was passed through to its members. As a corporation, we are treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this Annual Report which could have a material effect on the value of our reserves.
We may incur losses as a result of title defects in the properties in which we invest.
Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers to verify the rightful owners of the oil and gas interests prior to payment of such lease bonus to the lessor. There is no certainty, however, that a lessor has valid title to its lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
As of December 31, 2013, on a pro forma basis, approximately 58% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 352 Bcf of pro forma estimated proved undeveloped reserves will require an estimated $313 million of development capital over the next five years. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A writedown constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, are highly dependent on
our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
Conservation measures and technological advances could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our derivative activities could result in financial losses or could reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of natural gas, we enter into derivative instrument contracts for a significant portion of our natural gas production, including fixed-price swaps. As of December 31, 2013, we had entered into hedging contracts through December 31, 2017 covering a total of approximately 186 Bcf of our projected natural gas production at a weighted average price of $4.09 per MMBtu. For the period from January 1, 2014 until December 31, 2014, we have hedged approximately 62.9 Bcf of our projected natural gas production at a weighted average price of $4.05 per MMBtu. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
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production is less than the volume covered by the derivative instruments;
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the counterparty to the derivative instrument defaults on its contractual obligations;
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there is an increase in the differential between the underlying price in the derivative instrument and actual prices received;
or
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there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. As of December 31, 2013, the estimated fair value of our commodity derivative contracts was approximately $4.0 million. Any default by the counterparties to these derivative contracts, Wells Fargo Bank N.A. and Bank of Montreal, when they become due would have a material adverse effect on our financial condition and results of operations. In addition to the counterparties above at December 31, 2013, subsequent to December 31, 2013, we also executed hedging transactions with Barclays Bank PLC.
In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, which could also have an adverse effect on our financial condition.
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($6.4 million at December 31, 2013) and the sale of our natural gas production ($16.5 million in receivables as of December 31, 2013), which we market to two natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with two natural gas marketing companies. The largest purchaser of our natural gas during the year ended December 31, 2013 purchased approximately 94% of our operated production. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities that could exceed current expectations.
Substantial costs, liabilities, delays and other significant issues could arise from environmental laws and regulations inherent in drilling and well completion, gathering, transportation, and storage, and we may incur substantial costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, regional, state and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:
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Clean Air Act (“CAA”) and analogous state law, which impose obligations related to air emissions;
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Clean Water Act (“CWA”), and analogous state law, which regulate discharge of wastewaters and storm water from some of our facilities into state and federal waters, including wetlands;
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Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state law, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;
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Resource Conservation and Recovery Act (“RCRA”), and analogous state law, which impose requirements for the handling and discharge of any solid and hazardous waste from our facilities;
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National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environmental impacts of a proposed federal action before it is approved, such as drilling on federal lands;
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Safe Drinking Water Act (“SDWA”), and analogous state law, which restrict the disposal, treatment or release of water produced or used during oil and gas development;
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Endangered Species Act (“ESA”), and analogous state law, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and
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Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulates above ground storage tanks and sets forth liability for spills by responsible parties.
Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.
There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate may be located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.
In March 2010, the EPA announced its National Enforcement Initiatives for 2014 to 2016, which includes “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.
Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.
We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.
We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and any new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our products and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.
Changes in laws or government regulations regarding hydraulic fracturing could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our business.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing. The SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program and exempts hydraulic fracturing from the definition of “underground injection”. Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as require disclosure of the chemical constituents of the fluids used in the fracturing process. The U.S. Congress may consider similar SDWA legislation in the future. A final rule is expected some time in 2014.
In addition, EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and published final permitting guidance in February 2014 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. Also, in November 2011, the EPA announced its intent to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing and the agency currently plans to issue a Notice of Proposed Rulemaking that would seek public input on the design and scope of such disclosure regulations. To date, the EPA has not issued a Notice of Proposed Rulemaking; therefore, it is unclear how any federal disclosure requirements that add to any applicable state disclosure requirements already in effect may affect our operations. Further, on October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013, that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. The revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013.
Presently, hydraulic fracturing is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Along with several other states, Pennsylvania (where we conduct operations) has adopted laws and proposed regulations that require oil and natural gas operators to disclose chemical ingredients and water volumes used to hydraulically fracture wells, in addition to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases, and this may bring more public scrutiny to hydraulic fracturing operations. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. Although the Pennsylvania legislature passed legislation to make regulation of drilling uniform through the state, the Pennsylvania Supreme Court in Robinson Township v. Commonwealth of Pennsylvania
struck down portions of that legislation. Following this decision, local governments in Pennsylvania may increasingly adopt ordinances relating to drilling and hydraulic fracturing activities, especially within residential areas. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
The EPA is conducting a study of the potential impacts of hydraulic fracturing activities on drinking water. The EPA issued a Progress Report in December 2012 and a draft final report is anticipated by 2014 for peer review and public comment. As part of this study, the EPA requested that certain companies provide them with information concerning the chemicals used in the hydraulic fracturing process. This study or other studies may be undertaken by the EPA or other governmental authorities, and depending on their results, could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for our customers to perform fracturing. Any such regulations limiting or prohibiting hydraulic fracturing could reduce oil and natural gas exploration and production activities by our customers and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how hydraulic fracturing wastes are handled or disposed.
Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.
Water is an essential component of oil and natural gas production during the drilling, and in particular, hydraulic fracturing, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations.
Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Specific to Pennsylvania, sending wastewater to POTWs requires certain levels of pretreatment that may effectively prohibit such disposal as a disposal option and our continued ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.
We are subject to risks associated with climate change.
There is a growing belief that emissions of greenhouse gases (“GHGs”) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHGs and climate change creates the potential for financial risk. The U.S. Congress has previously considered legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions. For example, the Obama administration recently announced its Climate Action Plan, which, among other things, directs federal agencies to develop a strategy for the reduction of methane emissions, including emissions from the oil and gas sector.
On September 22, 2009, the EPA finalized a GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent (CO2e) emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, on November 8, 2010, the EPA issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas
facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO2e per year. The rule requires reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. We are required to report our GHG emissions to the EPA each year in March under this rule. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. Under a phased-in approach, for most purposes, new permitting provisions are required for new facilities that emit 100,000 tons per year or more of CO2e and existing facilities that make changes increasing emissions of CO2e by 75,000 metric tons. The EPA has indicated in rulemakings that it may further reduce these regulatory thresholds in the future, making additional sources subject to permitting.
The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Our natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of:
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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
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fires, explosions and ruptures of pipelines;
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personal injuries and death;
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natural disasters; and
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terrorist attacks targeting natural gas and oil related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
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injury or loss of life;
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damage to and destruction of property, natural resources and equipment;
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pollution and other environmental damage;
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regulatory investigations and penalties;
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suspension of our operations; and
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repair and remediation costs.
In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.
Since hydraulic fracturing activities are a large part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Properties that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities.
Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
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unexpected drilling conditions;
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title problems;
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pressure or lost circulation in formations;
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equipment failure or accidents;
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adverse weather conditions;
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compliance with environmental and other governmental or contractual requirements; and
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increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of businesses that complement or expand our current business, such as the Momentum Acquisition. However, we may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, our credit facilities impose certain limitations on our ability to enter into mergers or combination transactions. Our credit facilities and our convertible debentures also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
Market conditions or operational impediments may hinder our access to natural gas, NGL or oil markets or delay our production.
Market conditions or the unavailability of satisfactory natural gas, NGL or oil transportation arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGL or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.
Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, natural gas. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.
Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and have a material adverse effect on our financial condition and results of operations. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows. Further, the discharges of oil, natural gas, NGLs and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See “Item 1. Business-Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. We intend to continue our four-rig drilling program in the Marcellus Shale and two-rig drilling program in the Utica Shale; however, certain of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the Natural Gas Act of 1938, (“NGA”), exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”), as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the Energy Policy Act of 2005, or EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.
Competition in the natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.
We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.
We have grown rapidly over the last several years and more than doubled our employee workforce during 2013. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:
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increased responsibilities for our executive level personnel;
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increased administrative burden;
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increased capital requirements; and
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increased organizational challenges common to large, expansive operations.
Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations. We began development of our properties in 2010 with a two-rig drilling program. Recently, we expanded our development operations and are currently managing a six-rig drilling program. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.
Seasonal weather conditions and regulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors, including:
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recoverable reserves;
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future natural gas, NGL or oil prices and their applicable differentials;
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operating costs; and
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potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.
The Dodd-Frank Act, enacted on July 21, 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized some regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant”, others remain to be finalized and it is not possible at this time to predict when this will be accomplished.
The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s initial position limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, on November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.
The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.
Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is lower commodity prices.
Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.
Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.
The Fiscal Year 2014 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.
The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.
In February 2012, the state legislature of Pennsylvania passed a new natural gas impact fee in Pennsylvania. The legislation imposes an annual fee on natural gas and oil operators for each well drilled for a period of fifteen years. The fee is on a sliding scale set by the Public Utility Commission and is based on two factors: changes in the Consumer Price Index and the average NYMEX natural gas prices from the last day of each month. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed.
In February 2013, the governor of the state of Ohio proposed a plan to enact new severance taxes in fiscal 2014 and 2015. However, the Ohio State Senate did not include a severance tax increase in the version of the budget bill that it passed on June 7, 2013. The possibility remains that the severance tax increase on horizontal wells will resurface during compromise talks on the budget.
Risks Related to Our Common Stock
The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company, we are required to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of the NYSE, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We are required to:
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institute a more comprehensive compliance function;
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comply with rules promulgated by the NYSE;
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continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
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establish new internal policies, such as those relating to insider trading; and
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involve and retain to a greater degree outside counsel and accountants in the above activities.
Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2013, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, while we anticipate that we will cease to be an “emerging growth company” at the end of 2014, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management; and we may be unable to comply with these requirements in a timely or cost-effective manner.
In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.
In connection with past audits and reviews of our financial statements and those of our Marcellus joint venture, our independent registered public accounting firms identified and reported adjustments to management. Certain of such adjustments were deemed to be the result of internal control deficiencies that constituted a material weakness in internal controls over financial reporting. If we fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.
Prior to the completion of our IPO, we were a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. In addition, our Marcellus joint venture previously relied on our accounting personnel for its accounting processes. Historically, we and our Marcellus joint venture had not maintained effective internal control environments in that the design and execution of such controls had not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare the financial statements of us and our Marcellus joint venture. We concluded that these control deficiencies constituted material weaknesses in our control environment for the year ended December 31, 2012. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. The control deficiencies described above, at varying degrees of severity, contributed to the material weaknesses in the control environment as further described in “Item 9A. Controls and Procedures-Material Weaknesses in Internal Control over Financial Reporting.”
To address these control deficiencies, we have hired additional accounting and financial reporting staff, implemented additional analysis and reconciliation procedures and increased the levels of review and approval. Additionally, we have begun taking steps to comprehensively document and analyze our system of internal control over financial reporting in preparation for our first management report on internal control over financial reporting in connection with our annual report for the year ended December 31, 2014. Due to the recent implementation of these changes to our control environment, management continues to evaluate the design and effectiveness of these control changes in connection with its ongoing evaluation, review, formalization and testing of our internal control environment over the remainder of 2014. We will not complete our review until the second half of 2014 and we cannot predict the outcome of our review at this time. Based upon the status of our review, we and our independent auditors have concluded that the material weakness previously identified had not been remediated as of December 31, 2013. During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weakness previously identified. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.
For the year ended December 31, 2013, we were not required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, which require a formal assessment of the effectiveness of our internal control over financial reporting. As a public company, we are required to comply with the SEC’s rules implementing Section 302 of the Sarbanes Oxley Act of 2002, which require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Though we will be required to disclose material changes made to our internal controls and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 until the year following our first annual report required to be filed with the SEC. To comply with the requirements of being a publicly traded company, we have upgraded our systems, including information technology, implemented additional financial and management controls, reporting systems and procedures and hired additional accounting and finance staff. Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ending December 31, 2014, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, while we anticipate that we will cease to be an “emerging growth company” at the end of 2014, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our annual report for the fiscal year ending December 31, 2019. We can provide no assurance that our independent registered public accounting firm will be satisfied with the level at which our controls are documented, designed, or operating at the time it issues its report.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our shares of common stock.
Rice Holdings, Rice Partners and NGP Holdings collectively hold a substantial majority of our common stock.
Upon the completion of our IPO, Rice Holdings, Rice Partners and NGP Holdings held approximately 15.9%, 15.6% and 18.3% of our common stock, respectively. As such, Rice Holdings, Rice Partners and NGP Holdings have the collective voting power to elect all of the members of our board of directors (subject to the right of Alpha Natural Resources Inc. to designate one director) and thereby control our management and affairs. In addition, they are able to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and will be able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company. The existence of significant stockholders may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.
So long as Rice Holdings, Rice Partners and NGP Holdings continue to control a significant amount of our common stock, each will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of Rice Holdings, Rice Partners and NGP Holdings may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.
The stockholders’ agreement entered into in connection with the completion of our IPO permits our principal stockholders to designate a majority of the members of our board of directors.
In connection with the completion of our IPO, we entered into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc., pursuant to which Rice Holdings, NGP Holdings and Alpha Natural Resources, Inc. have certain rights relative to designated director nominees and agreed to vote their shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors.
Conflicts of interest could arise in the future between us and one or more of our sponsors concerning among other things, potential competitive business activities or business opportunities. Any actual or perceived conflicts of interest could have an adverse impact on the trading price of our common stock.
Our sponsors include other participants in the energy industry, including Natural Gas Partners, affiliates of Daniel J. Rice III (the Lead Portfolio Manager in the energy division at GRT Capital Partners) and Alpha Natural Resources Inc. Certain of our sponsors and/or their affiliates make investments in the U.S. oil and gas industry from time to time. As a result, our sponsors and/or their affiliates may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. In certain circumstances, they may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, certain of our sponsors and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours.
Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
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limitations on the removal of directors;
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limitations on the ability of our stockholders to call special meetings;
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establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders;
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providing that the board of directors is expressly authorized to adopt, or to alter or repeal our bylaws; and
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establishing advance notice and certain information requirements for nominations for election to our board of directors or for proposing matters that can be acted upon by stockholders at stockholder meetings.
We do not intend to pay dividends on our common stock, and our credit facilities place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.
We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our credit facilities place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it, for which there is no guarantee.
Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.
We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.
We are a “controlled company” within the meaning of the NYSE rules and, as a result, qualify for and avail ourself of exemptions from certain corporate governance requirements.
Rice Holdings, Rice Partners, NGP Holdings and Alpha Holdings collectively beneficially control a majority of the combined voting power of all classes of our outstanding voting stock. In connection with the completion of our IPO, we entered into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc., pursuant to which Rice Holdings, NGP Holdings and Alpha Natural Resources, Inc. have certain rights relative to designated director nominees and will agree to vote their shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors. As a result, we are a controlled company within the meaning of the NYSE corporate governance standards. Under the NYSE rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NYSE corporate governance requirements, including the requirements that:
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a majority of the board of directors consist of independent directors;
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the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;
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the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and
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there be an annual performance evaluation of the nominating and governance and compensation committees.
These requirements do not apply to us as long as we remain a controlled company. We have elected to utilize some of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE.
For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.
In April 2012, President Obama signed into law the JOBS Act. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period. We anticipate that we will cease to be an “emerging growth company” at the end of 2014.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.
The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline.
Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.
Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our amended and restated certificate of incorporation provides that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
The information required by Item 2 is contained in Item 1. Business.
Item 3.
Item 3. Legal Proceedings
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.
Item 4.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information. Our common stock is listed on the NYSE under the symbol “RICE.” As of December 31, 2013, our common stock was not listed on a domestic exchange or over-the-counter market. Our common stock began trading on the NYSE on January 24, 2014.
On March 20, 2014, the last sales price of our common stock, as reported on the NYSE, was $26.11 per share.
Holders. The number of shareholders of record of our common stock was approximately 46 as of March 17, 2014. The number of registered holders does not include holders that have shares of common stock held for them in “street name,” meaning that the shares are held for their accounts by a broker or other nominee. In these instances, the brokers or other nominees are included in the number of registered holders, but the underlying holders of the common stock that have shares held in “street name” are not.
Dividends. We have not paid any cash dividends since our inception. Covenants contained in our revolving credit facility restrict the payment of cash dividends on our common stock. We intend to retain all future earnings for the development and growth of our business, and we do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future.
Securities Authorized for Issuance under Equity Compensation Plans. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding our equity compensation plans as of December 31, 2013.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2013.
Use of Proceeds from Registered Securities.
On January 29, 2014, we completed our IPO of common stock pursuant to our registration statement on Form S-1 (File 333-192894) declared effective by the SEC on January 23, 2014. Barclays Capital Inc. acted as representative of the underwriters and Barclays Capital Inc., Citigroup Global Markets Inc., Goldman, Sachs & Co., Wells Fargo Securities, LLC, BMO Capital Markets Corp. and RBC Capital Markets, LLC acted as the joint book-running managers in the offering. Pursuant to the registration statement, we registered the offer and sale of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by us, 14,000,000 shares sold by the selling stockholder and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder. The sale of the shares in our IPO and the sale of shares covered by the option closed on January 29, 2014. Our IPO terminated upon completion of the closing.
The net proceeds of our IPO, based on the public offering price of $21.00 per share, were approximately $993.5 million, which resulted in net proceeds to us of $594.5 million after deducting estimated expenses and underwriting discounts and commissions of approximately $35.5 million and the net proceeds to the selling stockholders of approximately $399.0 million after deducting underwriting discounts of approximately $21.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. No fees or expenses have been paid, directly or indirectly, to any officer, director or 10% stockholder or other affiliate. A portion of the net proceeds from our IPO were used to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under our revolving credit facility. The remainder of the net proceeds from our IPO will be used to fund a portion of our capital expenditure plan.
Issuer Purchases of Equity Securities. Neither we nor any “affiliated purchaser” repurchased any of our equity securities in the quarter ended December 31, 2013.
Item 6.
Item 6. Selected Financial Data
Set forth below is our selected historical consolidated financial data as of and for the years ended December 31, 2013, 2012 and 2011. The selected historical consolidated financial data set forth below is not intended to replace our historical consolidated financial statements. You should read the following data along with “Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Risk Factors” included elsewhere in this Annual Report. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not give pro forma effect to (i) the completion of the corporate reorganization in connection with our initial public offering completed in January 2014 and (ii) the consummation of the Marcellus JV Buy-In, each as described under “Item 1. Business-Recent Developments.”
Overview
We are an independent natural gas and oil company engaged in the acquisition, exploration and development of natural gas and oil properties in the Appalachian Basin. We are focused on creating shareholder value by identifying and assembling a portfolio of low-risk assets with attractive economic profiles and leveraging our technical and managerial expertise to deliver industry-leading results. We strive to be an early entrant into the core of a shale play by identifying what we believe to be the core of the play and aggressively executing our acquisition strategy to establish a largely contiguous acreage position. We believe we were an early identifier of the core of both the Marcellus Shale in southwestern Pennsylvania and the Utica Shale in southeastern Ohio.
As of December 31, 2013, we held approximately 43,351 pro forma net acres in the southwestern core of the Marcellus Shale, primarily in Washington County, Pennsylvania. We established our Marcellus Shale acreage position through a combination of largely contiguous acreage acquisitions in 2009 and 2010 and through numerous bolt-on acreage acquisitions. In 2012, we acquired approximately 33,499 of our 46,488 net acres in the southeastern core of the Utica Shale, primarily in Belmont County, Ohio. We believe this area to be the core of the Utica Shale based on publicly available drilling results. We operate a substantial majority of our acreage in the Marcellus Shale and a majority of our acreage in the Utica Shale.
Since completing our first horizontal well in October 2010, our pro forma average net daily production has grown approximately 77 times to 154 MMcf/d for the fourth quarter of 2013. We have drilled and completed 37 pro forma horizontal Marcellus wells and 3 pro forma horizontal Upper Devonian wells as of December 31, 2013 with a 100% success rate (defined as the rate at which wells are completed and produce in commercially viable quantities). As of December 31, 2013, we had 1,313 gross (752 net) pro forma identified drilling locations, consisting of 349 gross (325 net) pro forma in the Marcellus Shale, 753 gross (233 net) pro forma in the Utica Shale and 211 gross (194 net) pro forma in the Upper Devonian Shale.
As of December 31, 2013, our pro forma estimated proved reserves were 602 Bcf, all of which were in southwestern Pennsylvania, with 42% proved developed and 100% natural gas.
Factors That Significantly Affect Our Financial Condition and Results of Operations
We derive substantially all of our revenues from the sale of natural gas that is produced from our interests in properties located in the Marcellus Shale. In the coming years, we expect to derive an increasing amount of our revenues from the sale of natural gas and, in a more limited amount, NGLs, that are produced from our interests in properties located in the Utica Shale. Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Natural gas prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars or natural disasters. In the future, we will also be subject to fluctuations in oil and NGL prices. Sustained periods of low natural gas prices could materially and adversely affect our financial condition, our results of operations, the quantities of natural gas that we can economically produce and our ability to access capital.
We use commodity derivative instruments, such as swaps and collars, to manage and reduce price volatility and other market risks associated with our natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. Our risk management activity is accomplished through over-the-counter commodity derivative contracts with large financial institutions. We use a combination of fixed price natural gas swaps; zero cost collars and deferred puts for which we receive a fixed price (via either swap price, floor of collar or put price) for future production in exchange for a payment of the variable market price received at the time future production is sold. The prices contained in these derivative contracts are based on NYMEX Henry Hub prices. The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differential, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. During the fourth quarter of 2013 we began hedging basis differentials associated with our natural gas production. We elected not to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore, changes in fair value of these derivative instruments are recognized in earnings. Please read “Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price risk and hedges
For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in natural gas prices, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Commodity Hedging Activities.”
Interest rate risks
On April 25, 2013, we entered into the term loan with a syndicate of banks. As of December 31, 2013, we had indebtedness outstanding under our term loan of $293.8 million which bears interest at a floating rate plus a fixed credit spread. The interest rate on this indebtedness as of December 31, 2013 was approximately 8.5%. As of December 31, 2013, our predecessor had $115.0 million in borrowings and approximately $22.5 million in letters of credit outstanding under our revolving credit facility. Concurrently with the closing of our IPO, we amended our revolving credit facility to, among other things, increase the maximum commitment amount to $1.5 billion and lower the interest rate owed on amounts borrowed under the revolving credit facility. After giving effect to the amendment, the borrowing base under our credit facility was increased to $350 million as a result of the Marcellus JV Buy-In. As of December 31, 2013, on a pro forma basis, we had availability under our revolving credit facility of approximately $317.1 million, as described in “-Recent Developments-Amendment to Senior Secured Revolving Credit Facility.” We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points following the closing of our IPO, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points following the closing of our IPO as a result of the Marcellus JV Buy-In, depending on the percentage of our borrowing base utilized.
Interest is payable in arrears at the end of each quarter and on the maturity date. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus 725 basis points with a minimum LIBOR rate of 1.25%. Base rate loans bear interest at a rate per annum equal to the greatest of (i) 2.25%, (ii) the agent bank’s reference rate, (iii) the federal funds effective rate plus 50 basis points and (iv) the rate for one month Eurodollar loans plus 100 basis points, plus 625 basis points. As of December 31, 2013, the 90-day LIBOR rate was approximately 0.25%, which is 1.00% lower than the minimum LIBOR rate on the term loan. Accordingly, a 100 basis point increase in the LIBOR rate would not materially change our interest expense. Based on the outstanding balance on the term loan as of December 31, 2013 a 100 basis point increase in the LIBOR rate beyond the minimum LIBOR rate of 1.25% would increase interest expense by $2.9 million per year.
As of December 31, 2013, we did not have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.
Counterparty and customer credit risk
Our principal exposures to credit risk are through joint interest receivables ($6.4 million as of December 31, 2013) and the sale of our natural gas production ($16.5 million in receivables as of December 31, 2013), which we market to two natural gas marketing companies. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our natural gas receivables with two natural gas marketing companies. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Item 8.
Item 8. Financial Statements and Supplementary Data
RICE ENERGY INC.
PRO FORMA CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Introduction
The following unaudited pro forma condensed consolidated financial statements of Rice Energy Inc. as of and for the year ended December 31, 2013 are derived from the historical financial statements of Rice Drilling B LLC and Alpha Shale Resources, LP set forth elsewhere in this Annual Report and are qualified in their entirety by reference to such historical financial statements and related notes contained therein. These unaudited pro forma condensed consolidated financial statements have been prepared to reflect our acquisition of a 50% interest in our Marcellus joint venture, our corporate reorganization and our initial public offering, each of which is described below.
Initial Public Offering
On January 29, 2014, we completed our IPO of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by us, 14,000,000 shares sold by the selling stockholder and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder.
The net proceeds of our IPO, based on the public offering price of $21.00 per share, were approximately $993.5 million, which resulted in net proceeds to us of $594.5 million after deducting estimated expenses and underwriting discounts and commissions of approximately $35.5 million and the net proceeds to the selling stockholders of approximately $399.0 million after deducting estimated expenses and underwriting discounts of approximately $21.0 million. We did not receive any proceeds from the sale of the shares by the selling stockholder. A portion of the net proceeds from our IPO were used to repay all outstanding borrowings under the revolving credit facility of our Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under our revolving credit facility. The remainder of the net proceeds from our IPO will be used to fund a portion of our capital expenditure plan.
Corporate Reorganization
A corporate reorganization occurred concurrently with the completion of our IPO on January 29, 2014. As a part of this corporate reorganization, we acquired all of the outstanding membership interests in Rice Appalachia, in exchange for shares of the Company’s common stock. Our business continues to be conducted through Rice Drilling B, as a wholly owned subsidiary. Upon (a) completion of the IPO, (b) the issuance of (i) 43,452,550 shares of common stock to NGP Holdings, (ii) 20,300,923 shares of common stock to Rice Holdings, (iii) 2,356,844 shares of common stock to Daniel J. Rice III, (iv) 20,000,000 shares of common stock to Rice Partners, (v) 160,831 shares of common stock to the persons holding incentive units representing interests in Rice Appalachia and (vi) 1,728,852 shares of common stock to the members of Rice Drilling B (other than Rice Appalachia), each of which were issued by us in connection with the closing of the IPO, and (c) the issuance of 9,523,810 shares of common stock to Alpha Holdings in connection with the completion of the Marcellus JV Buy-In described below under “-Marcellus JV Buy-In,” we had 127,523,810 shares of common stock outstanding.
Marcellus JV Buy-In
On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between us and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), we completed our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture in exchange for total consideration of $300 million, consisting of $100 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock.
The unaudited pro forma condensed consolidated balance sheet and the unaudited pro forma condensed consolidated statement of operations were derived by adjusting the historical audited and unaudited financial statements of our predecessor. The adjustments are based upon information available as of March 21, 2014, and certain estimates and assumptions. Actual effects of the transactions may differ from the pro forma adjustments. Management believes, however, that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments are factually supportable and give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial data.
The pro forma adjustments have been prepared as if the Marcellus JV Buy-In, the Reorganization and our IPO had each taken place on December 31, 2013, in the case of the unaudited pro forma condensed consolidated balance sheet, and as if the Marcellus JV Buy-In, the Reorganization and our IPO had each taken place as of January 1, 2013, in the case of the unaudited pro
forma condensed consolidated statements of operations for the year ended December 31, 2013. The unaudited pro forma condensed consolidated financial statements have been prepared on the fact that Rice Energy Inc. is treated as a corporation for federal income tax purposes. The unaudited pro forma condensed consolidated financial statements should be read in conjunction with the notes accompanying such unaudited pro forma financial statements and with the historical audited financial statements of Rice Drilling B LLC and Alpha Shale Resources, LP and related notes, as well as “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” each included elsewhere in the Annual Report.
The unaudited pro forma condensed consolidated financial statements give pro forma effect to the following adjustments, among others:
•
the acquisition of a 50% interest in our Marcellus joint venture from our joint venture partner in return for 9,523,810 shares of common stock of Rice Energy, Inc. and $100 million in cash;
•
the repayment of all outstanding borrowings under the revolving credit facility of us and our Marcellus joint venture;
•
the contribution by Rice Holdings, NGP Holdings and Daniel J. Rice III of their respective interests, and by Rice Partners of its remaining interest, in Rice Appalachia to Rice Energy Inc. in return for an aggregate of 86,110,317 shares of common stock of Rice Energy, Inc.;
•
the contribution by certain of the incentive unit holders of their respective remaining interest in Rice Appalachia to Rice Energy Inc. in exchange for 160,831 shares of common stock of Rice Energy Inc.;
•
the issuance of 1,728,852 shares of common stock of Rice Energy, Inc. to certain existing members of Rice Drilling B in exchange for their outstanding membership interests in Rice Drilling B; and
•
the issuance by Rice Energy, Inc. of 30,000,000 million common shares in the offering and the use of the net proceeds therefrom.
The unaudited pro forma condensed consolidated statement of operations excludes certain transaction costs, such as costs associated with the IPO that were not capitalized as part of the IPO. The unaudited pro forma condensed consolidated financial data are presented for illustrative purposes only and do not purport to indicate the financial condition or results of operations of future periods or the financial condition or results of operations that actually would have been realized had the transactions described above been consummated on the dates or for the periods presented.
The unaudited pro forma condensed consolidated financial statements constitute forward-looking information and are subject to certain risks and uncertainties that could cause actual results to differ materially from those anticipated. See “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”
RICE ENERGY INC.
PRO FORMA CONDENSED
CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 2013
(Unaudited)
See accompanying Notes to Pro Forma Financial Data (Unaudited).
RICE ENERGY INC.
PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
YEAR ENDED DECEMBER 31, 2013
(Unaudited)
See accompanying Notes to Pro Forma Financial Data (Unaudited).
RICE ENERGY INC.
NOTES TO PRO FORMA FINANCIAL DATA
(Unaudited)
1.
Basis of Presentation, Transactions and this Offering
The historical financial information is derived from the historical financial statements of our predecessor. The pro forma adjustments have been prepared as if the Marcellus JV Buy-In, the Reorganization and the IPO described in this Annual Report had each taken place on December 31, 2013, in the case of the unaudited pro forma condensed consolidated balance sheet, and as of January 1, 2013, in the case of the unaudited pro forma condensed combined statement of operations for the year ended December 31, 2013. The adjustments are based on information available as of March 21, 2014, and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments.
2.
Pro Forma Condensed Consolidated Balance Sheet Adjustments and Assumptions - Unaudited
The adjustments are based on information available as of March 21, 2014, and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A description of these transactions and adjustments is provided as follows:
(a)
Reflects the consolidation of Alpha Shale Resources, L.P. and elimination of the investment in joint ventures associated therewith as a result of the Marcellus JV Buy-In.
(b)
Reflects the impact of applying purchase accounting to the acquisition of Alpha Shale Resources, L.P. The assigned fair values are subject to final purchase accounting valuation adjustments under GAAP and may change. Reflects the impact of the transfer by Alpha Holdings of its 50% interest in Alpha Shale Resources, L.P. in exchange for $100.0 million of cash and the issuance of 9,523,810 shares of common stock to Alpha Holdings.
(c)
Reflects the receipt of $630 million of gross proceeds from the IPO from the issuance and sale of shares of common stock at the initial public offering price of $21.00 per share.
(d)
Reflects the payment of underwriting discounts totaling $31.5 million and additional estimated expenses related to the IPO of approximately $4.0 million.
(e)
Reflects the use of a portion of the net proceeds of the IPO to repay $115.0 million of borrowings under our revolving credit facility and $75.4 million of borrowings outstanding under the revolving credit facility of Alpha Shale Resources, L.P.
(f)
Reflects the estimated change in long-term deferred tax liabilities for temporary differences between the historical cost basis and tax basis of the Company’s assets and liabilities as the result of its change in tax status to a subchapter C corporation. A corresponding charge to earnings has not been reflected in the unaudited pro forma combined statements of operations as the charge is considered non-recurring.
3.
Pro Forma Condensed Consolidated Statement of Operations Adjustments and Assumptions - Unaudited
The adjustments are based on information available as of March 21, 2014, and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A description of these transactions and adjustments is provided as follows:
(a)
Reflects the consolidation of Alpha Shale Resources, L.P. and elimination of the investment in joint ventures associated therewith as a result of the Marcellus JV Buy-In.
(b)
Reflects the impact of applying purchase accounting to the acquisition of Alpha Shale Resources, L.P. The assigned fair values are subject to final purchase accounting valuation adjustments under GAAP and may change.
(c)
Reflects estimated incremental income tax provision assuming the earnings of Rice Drilling B, LLC and Alpha Shale Resources, L.P. had been subject to federal income tax as a subchapter C corporation using an effective tax rate of approximately 41%. This rate is inclusive of federal, state and local income taxes.
(d)
Reflects the elimination of interest expense related to the revolving credit facilities of Rice Drilling B, LLC and Alpha Shale Resources, L.P., which were repaid in full in connection with the IPO, partially offset by an increase in unused commitment fees related to the revolving credit facility of Rice Drilling B, LLC.
(e)
Reflects basic and diluted income per common share giving effect to (i) the conversion of restricted units in Rice Drilling B, LLC into shares of common stock in Rice Energy Inc. in connection with the corporate reorganization, (i) the issuance of 9,523,810 shares of common stock to Alpha Holdings as partial consideration of the Marcellus JV Buy-In and (iii) the issuance of 30,000,000 shares of common stock in the IPO. As we incurred a loss for the period presented, no dilutive impact occurred.
4.
Income Taxes - Unaudited
At the date of IPO, Rice Energy Inc. owned 100% of Rice Drilling B and Subsidiaries. Rice Drilling B was a limited liability company not subject to federal income taxes before IPO. However, in connection with the closing of the IPO, as a result of our corporate reorganization, we became a corporation subject to federal income tax and, as such, our future income taxes will be dependent upon our future taxable income. The change in tax status would require the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting deferred tax liability is approximately $145.1 million.
No current tax expense would result as of the date of the change in status. The recognition of the initial deferred tax liability will be recorded in equity at the date of IPO, but not in the financials as of December 31, 2013.
5.
Supplemental Information on Gas-Producing Activities - Unaudited
The historical pro forma supplemental natural gas disclosure is derived from the combined financial statements of Rice Drilling B and our Marcellus joint venture included elsewhere in this Annual Report and valuations prepared by the independent petroleum engineering firm of Netherland, Sewell and Associates, Inc. for us and our Marcellus joint venture. For information regarding our independent petroleum engineers and the basis and assumptions for our reserve estimates, please see Note 17 to the consolidated financial statements of Rice Drilling B and Note 11 to the financial statements for Alpha Shale Resources, LP as of and for the year ended December 31, 2013. The unaudited pro forma combined supplemental natural gas disclosures of the Company reflect the combined historical results of Rice Drilling B and Alpha Shale Resources, LP, on a pro forma basis to give effect to the transactions, described above, as if they had occurred on December 31, 2013 for pro forma supplemental natural gas disclosure purposes.
In accordance with SEC regulations, reserves at December 31, 2013 were estimated using the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing natural gas properties. Accordingly, the estimates may change as future information becomes available.
Pro forma reserve quantity information for the year ended December 31, 2013 is as follows (in millions of cubic feet, MMcf):
Extensions, Discoveries and Other Additions
On a pro forma basis, we added 140,249 MMcf through its drilling program in the Marcellus Shale in 2013.
Information with respect to our pro forma estimated discounted future net cash flows related to proved natural gas reserves as of December 31, 2013 is as follows (in thousands):
For information on our assumptions regarding pricing, please see Note 17 to the consolidated financial statements of Rice Drilling B and Note 11 to the financial statements for Alpha Shale Resources, LP as of and for the year ended December 31, 2013.
The following are the principal sources of changes in our pro forma standardized measure of discounted future net cash flows for 2013 (in thousands):
Gains on sales of interests in gas properties are not included in the information set forth above. We have also allocated certain general and administrative expenses to our results of operations as these expenses relate to production activities.
Report of Independent Registered Public Accounting Firm
The Members of
Rice Drilling B LLC
We have audited the accompanying consolidated balance sheets of Rice Drilling B LLC and subsidiaries as of December 31, 2013 and 2012, and the related consolidated statements of operations, cash flows and members’ capital for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Rice Drilling B LLC and subsidiaries at December 31, 2013 and 2012, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 21, 2014
RICE DRILLING B LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying Notes to Consolidated Financial Statements.
RICE DRILLING B LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying Notes to Consolidated Financial Statements.
RICE DRILLING B LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying Notes to Consolidated Financial Statements.
RICE DRILLING B LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS - (Continued)
See accompanying Notes to Consolidated Financial Statements.
RICE DRILLING B LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL
YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011
See accompanying Notes to Consolidated Financial Statements.
RICE DRILLING B LLC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies and Related Matters
Organization, Operations and Principles of Consolidation
The consolidated financial statements of the Company include the accounts of Rice Drilling B LLC (“the Company” or “Rice Drilling B”) and its wholly owned subsidiaries, Rice Drilling C LLC (“Rice C”), Rice Drilling D LLC (“Rice D”), RDB Real Estate Holdings LLC (“RDB Real Estate”), Blue Tiger Oilfield Services LLC (“Blue Tiger”), Rice Poseidon Midstream LLC (“Rice PM”), and Rice Olympus Midstream LLC (“Rice OM”). All significant intercompany accounts have been eliminated in consolidation.
The Company was organized as a Delaware limited liability company on February 12, 2008. Prior to the Company’s amended and restated LLC agreement dated November 13, 2009, Rice Energy Family Holdings, LP (formerly known as Rice Energy Limited Partnership) (“Rice Partners”) was the Company’s sole member. Effective November 13, 2009, separate classes of restricted units were authorized (see Note 9).
On January 25, 2012, Rice Partners, the sole owner of the Company’s preferred units and owner of 90% of the total units outstanding in the Company, assigned its preferred units in the Company to its wholly owned subsidiary, Rice Energy Appalachia LLC (“REA”). Concurrent with Rice Partners’ assignment of its units to REA, REA and Natural Gas Partners (“NGP”), a private equity firm, finalized a $100.0 million equity commitment to REA from NGP of which $75 million of NGP’s commitment was funded at closing on January 25, 2012. Cash proceeds from the investments were contributed by REA to Rice Drilling B. NGP received a put right with respect to their equity investment at REA which was contingently exercisable upon the occurrence of certain events. The earliest date that this put right could have been exercised is January 25, 2017. The fair value of this put right was de minimis given the accretion in fair value of REA. In conjunction with the equity investment in NGP, Daniel J. Rice III converted his outstanding promissory notes into equity of REA. On August 30, 2012, NGP funded the remaining $25 million of its commitment at REA.
During the year ended December 31, 2013, REA finalized a $300 million equity commitment from NGP, of which approximately $200 million was funded in April 2013 and contributed to Rice Drilling B. Cash proceeds from the investment were used to partially fund our Utica Shale leasehold acquisitions in southeastern Ohio. NGP’s equity commitments terminated in connection with the closing of the Rice Energy Inc. (“Rice Energy”) initial public offering (“IPO”).
In October 2013, Rice Energy was formed as a Delaware corporation for the purpose of becoming a publicly traded company and the holding company of Rice Drilling B. The historical financial information contained in this report relates to periods that ended prior to the completion of the IPO of Rice Energy. Consequently, the consolidated financial statements and notes thereto pertain to Rice Drilling B. In connection with the completion of its IPO on January 29, 2014, Rice Energy became a holding company whose sole material asset consists of a 100% indirect ownership interest in Rice Drilling B. As the sole managing member of Rice Drilling B, Rice Energy is responsible for all operational, management and administrative decisions relating to Rice Drilling B’s business and for periods subsequent to January 29, 2014, will consolidate the financial results of Rice Drilling B and its subsidiaries.
Rice Drilling B is the operating company of Rice Energy and as such is engaged in the acquisition, exploration, and development of natural gas properties in the Appalachian Basin.
Use of Estimates
The preparation of consolidated financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates and changes in these estimates are recorded when known.
Revenue Recognition
Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with the Company’s natural gas marketers. Pricing provisions are tied to the Platts Gas Daily market prices.
Cash
The Company maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed consolidated balance sheet amounts due to outstanding checks. The Company has no other accounts that are considered cash equivalents.
Accounts Receivable
Accounts receivable are primarily from the Company’s two gas marketers. The Company extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. There was no allowance recorded for any of the periods presented in the consolidated financial statements. Accounts receivable as of December 31, 2013 and 2012 are detailed below.
Investments in Joint Ventures
The Company accounts for its oilfield service company joint venture investment and for periods prior to the completion of the Marcellus JV Buy-In accounted for our Marcellus joint venture investment, under the equity method of accounting as we have significant influence, but not control, over the joint ventures as of December 31, 2013.
Under the equity method of accounting, investments are carried at cost, adjusted for the Company’s proportionate share of the undistributed earnings or losses and reduced for any distributions from the investment. The Company also evaluates its equity method investments for potential impairment whenever events or changes in circumstances indicate that there is an other-than-temporary decline in value of the investment. Such events may include sustained operating losses by the investee or long-term negative changes in the investee’s industry. These indicators were not present, and as a result, the Company did not recognize any impairment charges related to its equity method investments for any of the periods presented in the consolidated financial statements.
On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between it and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), Rice Energy completed its acquisition of Alpha Holdings’ 50% interest in its Marcellus joint venture (“Marcellus JV Buy-In”) in exchange for total consideration of $300 million, consisting of $100 million of cash and its issuance to Alpha Holdings of 9,523,810 shares of our common stock. See Note 15 for additional information.
Natural Gas Properties
The Company uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in gas properties, to drill and equip exploratory wells that result in proved reserves, are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. The Company wrote off approximately $8.1 million of costs associated with the drilling of the Bigfoot 7H in the fourth quarter of 2013.
Unproved gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the units of production method. Support equipment and other property and equipment not directly related to gas properties are depreciated over their estimated useful lives.
Management’s estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well
basis. Additionally, the Company adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Company’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Company’s depreciation, depletion, and amortization expense, a change in the Company’s estimated reserves could have a material effect on the Company’s operating results.
On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.
Interest
The Company capitalizes interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. Upon completion of construction of the asset, the associated capitalized interest costs are included within our asset base and depleted accordingly. The following table summarizes the components of the Company’s interest incurred for the periods indicated (in thousands):
Property and Equipment
Property and equipment are recorded at cost and are being depreciated over estimated useful lives of three to forty years on a straight-line basis. Accumulated depreciation was $1.3 million and $0.6 million at December 31, 2013 and 2012, respectively. Depreciation expense was $0.7 million, $0.6 million and $0.1 million for the years ended December 31, 2013, 2012 and 2011, respectively, and is included in depreciation, depletion, and amortization expense in the accompanying statements of consolidated operations.
Long-Lived Assets
Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less selling costs.
Deferred Financing Costs
Deferred financing costs are amortized on a straight-line basis, which approximates the interest method, over the term of the related agreement. Accumulated amortization was $14.3 million and $9.9 million at December 31, 2013 and 2012, respectively. Amortization expense was $5.2 million , $7.2 million and $2.7 million for the years ended December 31, 2013, 2012 and 2011, respectively. The annual amortization of deferred financing costs for years subsequent to December 31, 2013, is expected to be approximately $1.9 million in 2014, $1.9 million in 2015, $1.9 million in 2016, $1.9 million in 2017 and $1.1 million in 2018.
Delay Rental Agreements
The Company has leased drilling rights under agreements which specify additional payments for the privilege of deferring drilling operations for another year. Costs incurred to extend such agreements were $1.6 million and $3.1 million for the years ended December 31, 2013 and 2012, respectively.
Asset Retirement Obligations
The Company records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. The Company’s retirement obligations relate to the abandonment of gas-producing facilities and include costs to reclaim drilling sites and dismantle and relocate or dispose of gathering systems, wells, and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.
When a new liability is recorded, the Company capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.
Equity Incentives
The cost of employee and consultant services received in exchange for an award of equity instruments, such as restricted units, is measured based on the fair value of those instruments. Management established an estimated fair value for issued units based upon an income approach prior to December 31, 2013. At December 31, 2013, in connection with the IPO, a market approach was used. The restricted units are subject to a call option held by the Company which requires liability accounting for the restricted units. Details related to the restricted units are included in Notes 8 and 9.
Income Taxes
The Company is treated as a partnership for federal and state income tax purposes. Consequently, the Company is not subject to income taxes; instead its members include the income in their tax returns.
Reclassifications
Certain reclassifications have been made to prior periods’ financial information related to post production costs, restricted unit liability and asset retirement obligations to conform to the 2013 presentation.
Correction of Errors
The Company’s net income for the year ended December 31, 2012 included expense of approximately $1.7 million that related to prior periods. These corrections resulted in additional exploration expense of approximately $1.1 million, lease operating expense of $0.5 million, and other expense of $0.1 million recorded in 2012. These errors were not material to prior periods, individually or in the aggregate, and were not material to the 2012 period. These errors did not impact debt covenant compliance nor distort operating results. Therefore, these items were corrected in fiscal 2012.
2.
Capitalized Costs Relating to Gas-Producing Activities
Proved and unproved capitalized costs related to the Company’s gas-producing activities are as follows (in thousands):
3.
Sale of Interests in Gas Properties
In December 2013, the Company agreed to sell interests in noncore assets in Guernsey County, Ohio and Lycoming County, Pennsylvania in two separate transactions. The Company agreed to sell an undivided 75.0% interest in certain of its Guernsey County leaseholds (representing approximately 2,136 net acres) to a third party in exchange for approximately $22.0 million, consisting of $11.0 million in cash and an $11.0 million carried working interest. Of the 2,136 net acres, 1,033 net acres closed subsequent to December 31, 2013. No gain or loss was recorded on this transaction.
In addition, the Company sold all of its Lycoming County acreage (100% non-operated) and related assets to another third party in exchange for $7.0 million of which $6.0 million will be paid on or before April 30, 2014. This receivable is included in accounts receivable on the accompanying consolidated balance sheet. There was no production or net proved reserves attributable to the interests sold in either transaction. The Company incurred a loss of $4.2 million in the fourth quarter of 2013 as a result of this transaction.
In March 2011, the Company entered into a joint operating agreement with US Energy Development Corporation (US Energy) covering those certain properties whereby the Company sold a 50% non-operated working interest in the properties to US Energy. Subsequent to this transaction, the Company owns a 50% working interest in approximately 1,000 acres in the Whipkey field and has retained operatorship. The Company received cash consideration of $1.7 million and recorded a gain of $1.5 million on this transaction in the accompanying consolidated statements of operations.
Long-term debt consists of the following as of December 31, 2013 and 2012 (in thousands):
Debentures (a)
In June of 2011, the Company sold $60.0 million of its 12% Senior Subordinated Convertible Debentures due 2014 (“the Debentures”) in a private placement to certain accredited investors as defined in Rule 501 of Regulation D. The Debentures accrue interest at 12% per year payable monthly in arrears by the 15th day of the month and mature on July 31, 2014 (“Maturity Date”). The Debentures are the Company’s unsecured senior obligations and rank equally with all of the Company’s current and future senior unsecured indebtedness.
From July 31, 2013 through August 20, 2013 (“the put redemption period”), any holder of Debentures had the right to cause the Company to repurchase all or any portion of the Debentures owned by such holder at 100% of the portion of the principal amount of the Debentures as to which the right was being exercised, plus a premium of 20%. During the put redemption period, the Company repurchased $53.1 million of outstanding Debentures and paid a put premium of $10.6 million in accordance with the terms of the agreements. The put redemption period expired in the nine months ended September 30, 2013 and the Company recorded the premium of $10.6 million as a loss on extinguishment of debt in the statement of consolidated operations for the year ended December 31, 2013.
At any time after July 31, 2013 until the Maturity Date, the Company has the right to redeem all, but not less than all, of the Debentures on 30 days prior written notice at a redemption price equal to 100% of the principal amount of the Debentures plus a premium of 50%. In connection with the IPO, the convertible debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for an aggregate 1,671,800 shares of common stock of Rice Energy Inc. Through March 10, 2014, approximately $5.0 million of the convertible debentures had been converted into 433,073 shares of Rice Energy Inc. common stock. On February 28, 2014, the Company issued a call notice on the remaining convertible debentures, requiring a
response by March 30, 2014. Amounts not converted by the redemption date will receive a cash payment from the Company of 100% of the principal amount plus a premium of 50%, which could result in additional costs of $1.0 million if all remaining convertible debentures are redeemed. As the principal amount of the convertible debentures outstanding has been reduced to less than $5.0 million, the Company is no longer required to maintain restricted cash.
In connection with the convertible debt offering, Rice Drilling B granted warrants that were issued on August 15, 2011, to certain of the broker-dealers involved in the private placement. These warrants are considered to be separate instruments issued solely in lieu of cash compensation for services provided by the broker-dealers. Two separate classes of warrants were issued (Normal and Bonus), the sole difference being the exercise price.
The fair value of these warrants at the date of grant was estimated using the Black-Scholes valuation model with the following assumptions:
The fair value of $3.3 million of the above warrants were recorded as a deferred financing cost during the year ended December 31, 2011, and were amortized over the term of the Debentures. Subsequent to December 31, 2013, two warrants had been exercised in exchange for 1,728 shares of Rice Energy Inc. common stock. If all warrants are exercised approximately 1.1 million shares of Rice Energy Inc. common stock would be issued.
Wells Fargo Energy Capital Credit Facility (b)
In November of 2012, the Company amended and restated its then existing credit facility with Wells Fargo. In connection with the amendment and restatement, a lender was added to the new facility. The amendment and restatement was accounted for as a modification of the debt, resulting in $0.2 million of third-party costs associated with the amendment and restatement being expensed. The Wells Fargo Energy Capital Credit Facility (“Wells Fargo Energy Capital Credit Facility”) was subject to a maximum borrowing base equal to $200.0 million, as determined unanimously by Wells Fargo Energy Capital, in accordance with customary lending practices. This loan was repaid using proceeds from the Second Lien Term Loan Facility during the second quarter of 2013.
Second Lien Term Loan Facility (c)
On April 25, 2013, the Company entered into a Second Lien Term Loan Facility (“Second Lien Term Loan Facility”) with Barclays Bank PLC, as administrative agent, and a syndicate of lenders in an aggregate principal amount of $300.0 million. The Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $4.5 million. The discount is being amortized over the life of the note using an effective interest rate of 0.284% using the effective yield method. As of December 31, 2013, the Company had a balance of $293.8 million relating to the Second Lien Term Loan Facility, this includes borrowings outstanding of $297.7 million less a discount of $3.9 million. The Second Lien Term Loan Facility matures October 25, 2018. Approximately $7.3 million in fees were capitalized in connection with the Second Lien Term Loan Facility.
Principal amounts borrowed under the Second Lien Term Loan Facility are payable in an amount equal to 0.25% of the initial principal amount at the end of each quarter with the remainder payable on the maturity date. Interest is payable in arrears at the end of each quarter and on the maturity date. The Company has the choice to borrow in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus 725 basis points. Base rate loans bear interest at a rate per annum equal to the greatest of (i) 2.25%, (ii) the agent bank’s reference rate, (iii) the federal funds effective rate plus 50 basis points and (iv) the rate for one month Eurodollar loans plus 100 basis points, plus 625 basis points. The Company may prepay the borrowings under the Second Lien Term Loan Facility at any time, provided that any prepayments of principal amounts during the first year following the closing date are subject to a 2% premium and any prepayments of principal during the second year following the closing date are subject to 1% premium. The interest rate was 8.5% as of December 31, 2013.
The Second Lien Term Loan Facility is secured by liens on substantially all of the Company’s properties that are subordinated to the liens securing the revolving credit facility and guarantees from the Company’s subsidiaries other than any subsidiary that have been designated as an unrestricted subsidiary. The Second Lien Term Loan Facility contains restrictive covenants that may limit the Company’s ability to, among other things:
•incur additional indebtedness;
•sell assets;
•withdraw funds from specified restricted account;
•make loans to others;
•make investments;
•enter into mergers;
•make or declare dividends;
•hedge future production or interest rates;
•incur liens; and
•engage in certain other transactions without the prior consent of the lenders.
The Second Lien Term Loan Facility also requires the Company to maintain an asset coverage ratio, which is the ratio of the present value of oil and gas reserves (discounted at 10% per annum) to the sum of all secured debt (including any debt incurred by the Company’s Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0.
The Company was in compliance with such covenants and ratios as of December 31, 2013.
NPI Note (d)
In November of 2012, in connection with the amendment of the Wells Fargo Credit Facility, the Company repurchased the NPI it had previously assigned to Wells Fargo for $26.5 million, of which $9.5 million was paid at the closing of the Wells Fargo Energy Capital Credit Facility and $17.0 million was financed by a note to Wells Fargo. The Company accounted for this as the acquisition of a mineral right and therefore capitalized this amount in proved properties and will amortize using the units of production method. There is no stated interest rate associated with this note and as a result, this note was considered to have below market financing rates. The Company estimated the discount on issuance of this instrument based upon an estimate of market rates at the inception of the instrument and recorded a discount of $2.0 million. The discount is being amortized over the life of the note using an effective interest rate of 12.10% using the effective yield method. As part of the use of proceeds from the Second Lien Term Loan Facility, the Company repaid $8.5 million of this note during the second quarter of 2013. A final payment of $8.5 million is due to be repaid in June of 2014.
Senior Secured Revolving Credit Facility (e)
On April 25, 2013, the Company entered into a revolving credit facility with Wells Fargo Bank, N.A., as administrative agent, and a syndicate of lenders with a maximum credit amount of $500.0 million and a sublimit for letters of credit of $10.0 million. As of December 31, 2013, the sublimit for the letters of credit was $100.0 million. The amount available to be borrowed under the revolving credit facility is subject to a borrowing base that is redetermined semiannually as of each January 1 and July 1 and depends on the volumes of our proved oil and gas reserves and estimated cash flows from these reserves and our commodity
hedge positions. The next redetermination is scheduled to occur in April 2014. As of December 31 2013, the borrowing base was $200.0 million. As of December 31, 2013, we had $115.0 million in borrowings and approximately $22.5 million in letters of credit outstanding under our revolving credit facility. The revolving credit facility matures April 25, 2018.
Principal amounts borrowed are payable on the maturity date, and interest is payable quarterly for base rate loans and at the end of the applicable interest period for Eurodollar loans. The Company has a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 175 to 275 basis points, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 75 to 175 basis points, depending on the percentage of our borrowing base utilized. The Company may repay any amounts borrowed prior to the maturity date without any premium or penalty other than customary LIBOR breakage costs. The weighted average interest rate was 2.39% as of December 31, 2013.
The credit facility is secured by liens on substantially all of the properties of the Company and guarantees from its subsidiaries other than any subsidiary that we have designated as an unrestricted subsidiary. The credit facility contains restrictive covenants that may limit our ability to, among other things:
•
incur additional indebtedness;
•
sell assets;
•
make loans to others;
•
make investments;
•
enter into mergers;
•
make or declare dividends;
•
hedge future production or interest rates;
•
incur liens; and
•
engage in certain other transactions without the prior consent of the lenders.
The credit facility also requires the Company to maintain the following three financial ratios, which are measured at the end of each calendar quarter:
•
a current ratio, which is the ratio of the Company’s consolidated current assets (includes unused commitment under the credit facility and excludes derivative assets) to its consolidated current liabilities, of not less than 0.75 to 1.0 as of March 31, 2013 and 1.0 to 1.0 at the end of each fiscal quarter thereafter;
•
a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX based on the trailing twelve month period to consolidated interest expense, of not less than 2.5 to 1.0; and
•
an asset coverage ratio, which is the ratio of the present value of the Company’s oil and gas reserves (discounted at 10% per annum) to the sum of all our secured debt (including 50% of any debt incurred by the Company’s Marcellus joint venture under its credit facility or any replacement or refinancing of its credit facility) of not less than 1.5 to 1.0 so long as any debt is outstanding under the term loan facility.
The Company was in compliance with such covenants and ratios as of December 31, 2013.
Concurrently with the closing of Rice Energy’s IPO, the Company amended its revolving credit facility to, among other things, increase the maximum commitment amount to $1.5 billion and lower the interest rate owed on amounts borrowed under the revolving credit facility. After giving effect to the amendment, the borrowing base under the credit facility was increased to $350 million as a result of the Marcellus JV Buy-In. Eurodollar loans under the amended revolving credit facility bear interest at a rate per annum equal to LIBOR plus an applicable margin ranging from 150 to 250 basis points, depending on the percentage of borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 100 basis points, plus an applicable margin ranging from 50 to 150 basis points, depending on the percentage of borrowing base utilized. The Company will be subject to the same financial ratios and substantively the same restricted covenants as under the revolving credit facility prior to such amendment. The amended revolving credit facility will mature upon the earlier of the date that is five years
following the closing of the amendment and the date that is 180 days prior to the maturity of the second lien term loan facility, if any amounts are outstanding under that facility as of such date.
Expected aggregate maturities of notes payable subsequent to December 31, 2013, are as follows (in thousands):
Interest paid in cash was $27.7 million and $10.2 million for years ended December 31, 2013 and 2012, respectively. See Note 1 for information on capitalized interest.
5.
Fair Value of Financial Instruments
The Company determines fair value on a recurring basis for its liability related to restricted units and recorded amounts for derivative instruments as these instruments are required to be recorded at fair value for each reporting amount. Certain amounts in the Company’s financial statements are measured at fair value on a nonrecurring basis including discounts associated with long-term debt. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.
The Company has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The Company’s fair value measurements relating to restricted units are included in Level 3. The Company’s fair value measurements relating to derivative instruments are included in Level 2. Since the adoption of fair value accounting, the Company has not made any changes to its classification of financial instruments in each category.
Items included in Level 3 are valued using internal models that use significant unobservable inputs. Items included in Level 2 are valued using management’s best estimate of fair value corroborated by third-party quotes.
The following liabilities were measured at fair value on a recurring basis during the period (refer to Notes 9 and 11 for details relating to the restricted units and derivative instruments) (in thousands):
Gains and losses related to restricted units included in earnings for the period are reported in operating expenses in the statements of consolidated operations.
The carrying value of cash equivalents approximates fair value due to the short maturity of the instruments.
The estimated fair value of long-term debt on the consolidated balance sheets at December 31, 2013 and 2012 is shown in the table below (refer to Note 4 for details relating to the borrowing arrangements) (in thousands). The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Company’s financial position.
The Company leases drilling rights under agreements which expire at various times. The following represents the future minimum lease payments under the agreements as of December 31, 2013 (in thousands):
These lease payments are included as leasehold payables in the accompanying consolidated balance sheets.
Additionally, the Company has leased drilling rights under agreements which specify additional payments due in the event that the Company does not meet predetermined criteria within a specified period of time. The Company could be required to pay up to approximately $2.0 million, $1.0 million and $0.3 million in 2014, 2015 and 2016, respectively, under these agreements.
7.
Asset Retirement Obligations
The Company is subject to certain legal requirements which result in recognition of a liability related to the obligation to incur future plugging and abandonment costs. The Company records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Company’s credit adjusted risk-free rate.
A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2013 and 2012 is as follows (in thousands):
Members include consultants and employees of the Company as well as REA. The liability of the members of the Company is limited to each member’s total capital account. Subsequent to a 4:1 stock split on June 22, 2011, authorized capital consisted of 36,000 preferred units, 2,000 Class A units, and 2,000 Class B units as of December 31, 2011. The consolidated financial statements have been adjusted to reflect the impact of the stock split for all periods presented, where applicable.
As of December 31, 2012, all units of Class A units were reserved for issuance pursuant to a Restricted Unit Agreement (see Note 9). As discussed in Note 1, the founding member, Rice Partners, assigned its 36,000 preferred units to REA. Additionally, in connection with NGP’s $100.0 million equity investment into REA in 2012, of which 100% of the net proceeds were invested into Rice Drilling B, Rice Drilling B issued 15,998 preferred units to REA. Operating profits and losses are to be allocated in proportion to the members’ interest.
During 2013, the Company finalized a $300.0 million equity commitment from NGP of which approximately $200.0 million of NGP’s commitment was funded at closing in April 2013. Cash proceeds from the investment were used to fund Utica Shale leasehold acquisitions in southeastern Ohio. As a part of the reorganization that occurred in connection with the Rice Energy IPO, the Company became a wholly-owned subsidiary of REA and the restricted units were exchanged for common stock of Rice Energy. Furthermore, NGP’s equity commitments terminated in connection with the closing of the Rice Energy IPO.
Liquidation Preference
Prior to the reorganization in connection with the Rice Energy IPO, the terms of the governance documents of the Company provided that in the event of any liquidation, dissolution or winding up of the Company, distributions would first be made to members holding senior preferred units until such members have received cumulative distributions in an amount equal to the preferred return as defined in the REA agreement, second to the members holding preferred units in the amount of $49.9 million, then, until the Company had achieved breakeven operations, as defined, to the members holding preferred and Class A common units in proportion to their ownership interests and thereafter to the members in proportion to their ownership units. Following the restructuring, distributions in such event would be made to the sole member.
Repurchase Option
Up until the third anniversary of the grant of Class A and B restricted units, the Company or a member of its affiliates had the right to repurchase all of the units from the member at $1,700 per unit, as defined and in accordance with the Company’s then-existing limited liability company agreement. Subsequent to the third anniversary of the grant of Class A and B restricted units, the Company or a member of its affiliates has the right to repurchase all of the units from the member at fair market value, not less than $1,700 per unit, in accordance with the Company’s then-existing limited liability company agreement.
During 2012, REA exercised the option to repurchase all units of the 2,000 Class B restricted units for $3.4 million. In December 2012, a payment of $1.1 million was made by the Company to the member on behalf of REA. Additional payments of $2.3 million were made by the Company on behalf of REA in 2013. The Company was reimbursed these costs.
Voting Rights
Preferred units have voting rights whereas the restricted units (Class A and B common units) are nonvoting.
9.
Restricted Unit Agreements
Effective November 13, 2009, the Company entered into restricted unit agreements with an employee and consultants. Under separate and individual restricted unit agreements, the eligible employee and consultants are granted units which vest over a specified period of time. Each unit entitles the holder to an equity ownership in the Company. The restricted units are accounted for as liability awards, which require remeasurement each reporting period, as a result of the existence of a call option that permits the Company to repurchase the awards at a fixed amount that could be above or below fair market value of the units. Prior to November 13, 2012, the Company had the ability to exercise the call option at a specified amount. Subsequently, the Company’s call right is at fair market value. As of December 31, 2013, the remaining liability recorded for the restricted units represented fair value. Management established an estimated fair value for issued units based upon an income approach prior to December 31, 2013. The income approach requires use of internal business plans that are based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors. At December 31, 2013, in connection with the Rice Energy IPO, a market approach was used.
During 2012, REA exercised its option to repurchase all of the 2,000 Class B restricted units. A summary of the change in vested restricted units is as follows:
REA, as the parent company of Rice Drilling B, granted Incentive Units to certain members of management. The Incentive Units are not accounted for as equity instruments as the Incentive Units do not have the characteristics of a substantive class of equity. Rather, the Incentive Units provide the holders with a performance bonus for fair value accretion of REA equity. In connection with the January 2012 NGP investment in REA, 100,000 Tier I Legacy units, 13,000 Tier II Legacy units, and 17,000 Tier III Legacy units were issued. The Incentive Units will only be paid in cash and payout for each tier occurs when a specified level of cumulative cash distributions has been received by NGP.
In connection with the April 2013 NGP investment in REA, an additional 900,000 Tier I Legacy units, 987,000 Tier II Legacy Units and 983,000 Tier III Legacy Units were issued. In addition, 100,000 New Tier I Units, 100,000 New Tier II Units, 100,000 New Tier III Units, and 100,000 New Tier IV Units were issued. In June 2013, an additional 717,546 New Tier I Units, 577,546 New Tier II Units, 577,546 New Tier III Units, and 577,546 New Tier IV Units were issued to certain members of management. Similar to above, there is no payout of the awards until specified level of cumulative cash distributions has been received by NGP.
During 2012 and 2013, no payments were made in respect of Incentive Units. The Company has not recognized compensation cost on the Incentive Units because the payment conditions, which relate to a liquidity event are not probable at December 31, 2013. The estimated payout under these awards at December 31, 2013 is approximately $142.3 million if a liquidity event were to occur. Prior to December 31, 2013, this estimate was based upon an option pricing model with various Level 3 assumptions including internal business plans that were based on judgments and estimates regarding future economic conditions, costs, inflation rates and discount rates, among other factors. To the extent market transactions were known, this information was factored into the fair value estimate. At December 31, 2013, the Company no longer used an income approach to estimate the fair value and instead utilized a market approach to estimate the fair value. This change in fair value method was a result of the Rice Energy IPO.
On January 23, 2014, in connection with our IPO and corporate reorganization, the incentive units described above were modified. As a result of these modifications, certain of these incentive units are to be settled in cash and others are to be settled by the issuance of stock. The Company has not yet quantified the amount of the expense associated with the modifications.
The Company uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. Our derivative counterparties share in the Credit Agreement collateral. The Company’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently. As of December 31, 2013, the Company entered into derivative instruments with Wells Fargo Bank, N.A. and Bank of Montreal fixing the price it receives for natural gas through November 28, 2017, as summarized in the following table:
The following is a summary of the Company’s derivative instruments, which are recorded in the consolidated balance sheets as of December 31, 2013 and 2012 (in thousands):
The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value (in thousands):
Both realized and unrealized gains and losses are recorded as a gain or loss on derivatives in the consolidated statement of operations under other income/expense.The Company had an unrealized gain of $6.2 million for the year ended December 31, 2013 and an unrealized loss of $2.3 million for the year ended December 31, 2012. There were no unrealized gains or losses for the year ended December 31, 2011. The Company had realized gains related to contract settlements of $0.7 million, $0.9 million and $0.6 million for the years ended December 31, 2013, 2012 and 2011 respectively.
On October 14, 2013, the Company entered into a Development Agreement and Area of Mutual Interest (“AMI”) Agreement with Gulfport Energy Corporation (“Gulfport”) covering approximately 50,000 aggregate net acres in the Utica Shale in Belmont County, Ohio. The Company refers to these agreements as “Utica Development Agreements.” Pursuant to the Utica Development Agreements, the Company had approximately 68.80% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Goshen and Smith Townships (the “Northern Contract Area”) and an approximately 42.63% participating interest in acreage currently owned or to be acquired by the Company or Gulfport located within Wayne and Washington Townships (the “Southern Contract Area”), each within Belmont County, Ohio. The remaining participating interests are held by Gulfport. The participating interests of the Company and Gulfport in each of the Northern and Southern Contract Areas approximate the Company’s current relative acreage positions in each area.
Each quarter during the term of the Development Agreement, the Company and Gulfport will establish a work program and budget detailing the proposed exploration and development to be performed in the Northern and Southern Contract Areas, respectively, for the following year. The number of horizontal wells proposed to be drilled in each of the Northern Contract Area and Southern Contract Area is limited by the Development Agreement as follows: in 2013, no more than five wells; in 2014, between eight and 40 wells; in 2015, between eight and 50 wells; and thereafter, unlimited.
The Utica Development Agreements have terms of ten years and are terminable upon 90 days’ notice by either party; provided that, with respect to interests included within a drilling unit, such interests shall remain subject to the applicable joint
operating agreement and the Company and Gulfport shall remain operators of drilling units located in the Northern AMI and Southern AMI, respectively, following such termination.
The Company is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.
The Company has commitments for gathering and firm transportation under existing contracts with third parties. Future payments for these items as of December 31, 2013 totaled $637.2 million (2014 - $28.3 million, 2015 - $52.1 million, 2016 - $65.6 million, 2017 - $65.4 million, 2018 - $64.0 million and thereafter - $361.8 million).
As of December 31, 2013, the Company had two horizontal drilling rigs under contract. One of these contracts expires in 2014. A third rig, which we took delivery of in February 2014, expires in 2015. Future payments for these items as of December 31, 2013 totaled $21.4 million (2014 - $11.7 million and 2015 - $9.7 million). Any other rig performing work for us is doing so on a well-by-well basis and therefore can be released without penalty at the conclusion of drilling on the current well. These types of drilling obligations have not been included in the amounts above. The values above represent the gross amounts that we are committed to pay without regard to our proportionate share based on our working interest.
Capital leases are entered into for vehicle purchases. The acquisition value of vehicles recorded under capital leases is $2.0 million. Accumulated amortization related to capital leases was $0.2 million and $8 thousand as of December 31, 2013 and 2012, respectively. Amortization expense related to capital leases was $0.2 million, $8 thousand and $0 as of December 31, 2013, 2012 and 2011, respectively. Future lease payments under capital leases as of December 31, 2013 totaled $1.6 million (2014 - $0.4 million, 2015 - $0.3 million, 2016 - $0.3 million, 2017 - $0.5 million and 2018 - $0.1 million).
Operating leases are primarily entered into for various office locations. Rental expense under operating leases was $0.2 million, $0.2 million and $0.1 million for the years ended December 31, 2013, 2012 and 2011, respectively. Future lease payments under non-cancelable operating leases as of December 31, 2013 totaled $4.5 million (2014 - $0.6 million, 2015 - $1.0 million, 2016 - $0.9 million, 2017 - $0.8 million, 2018 - $0.8 million and thereafter - $0.4 million).
In prior periods, the Company reimbursed Rice Partners for expenses incurred on behalf of the Company. General and administrative expenses incurred by Rice Partners and reimbursed by the Company were $9.3 million, $4.8 million and $3.1 million for the years ended December 31, 2013 , 2012 and 2011, respectively. As of December 31, 2013 and 2012, $6.1 million and $2.5 million, respectively, of general and administrative expenses was due to Rice Partners and is recorded as due to affiliate on the consolidated balance sheet. Prior to the closing of the Rice Energy IPO, the Company terminated its agreement to reimburse Rice Partners for expenses incurred on its behalf.
Payments totaling $2.2 million, $0.8 million and $0.6 million were made during the years ended December 31, 2013, 2012 and 2011 respectively to Geological Engineering Services, Inc. (“GES”) in respect of consultancy services. GES is a drilling and completion engineering consulting company specializing in unconventional reservoirs like the Marcellus Shale. John P. LaVelle, Rice Energy’s Vice President of Drilling, served as president of GES from February 1994 until February 2010. There were no amounts outstanding between the Company and GES as of any period presented.
The Company was reimbursed for costs incurred on behalf of the Company’s Marcellus joint venture. General and administrative expenses incurred by the Company and reimbursed by the Company’s Marcellus joint venture were $1.6 million, $1.3 million and $0.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.
As of December 31, 2012, the Company recorded a receivable from its Marcellus joint venture for $6.0 million representing capitalized costs that were approved to be contributed to the joint venture.
On December 31, 2012, the Company entered into a transaction to acquire certain producing shallow natural gas wells and unproved properties (the “Shallow-Well Acquisition”). Total firm consideration in the Shallow-Well Acquisition was approximately $10.0 million of which $3.3 million was paid to the seller in January 2013. An additional $1.0 million was paid to the seller as of December 31, 2013, reducing the notes payable. The remaining consideration will be transferred to the seller from 2014 to 2015. In addition to the firm consideration, the seller has the right to participate in the development of the unproved properties and the Company is responsible for funding $3.7 million of these activities. The Company has recorded the $10.0 million purchase price with the offset to proved and unproved properties.
Initial Public Offering
On January 29, 2014, Rice Energy completed their IPO of 50,000,000 shares of our $0.01 par value common stock, which included 30,000,000 shares sold by Rice Energy Inc., 14,000,000 shares sold by the selling stockholder and 6,000,000 shares subject to an option granted to the underwriters by the selling stockholder.
The net proceeds of the IPO, based on the public offering price of $21.00 per share, were approximately $993.5 million, which resulted in net proceeds to Rice Energy of $594.5 million after deducting estimated expenses and underwriting discounts and commissions of approximately $35.5 million and the net proceeds to the selling stockholders of approximately $399.0 million after deducting underwriting discounts of approximately $21.0 million. Rice Energy did not receive any proceeds from the sale of the shares by the selling stockholders. A portion of the net proceeds from the IPO were used to repay all outstanding borrowings under the revolving credit facility of the Company’s Marcellus joint venture, to make a $100.0 million payment to Alpha Holdings in partial consideration for the Marcellus JV Buy-In and to repay all outstanding borrowings under the Company’s revolving credit facility. The remainder of the net proceeds from the IPO will be used to fund a portion of our capital expenditure plan.
Marcellus JV Buy-In
On January 29, 2014, in connection with the closing of the IPO and pursuant to the Transaction Agreement between Rice Energy and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), Rice Energy completed its acquisition of Alpha Holdings’ 50% interest in the Company’s Marcellus joint venture in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and the issuance to Alpha Holdings of 9,523,810 shares of Rice Energy common stock. Prior to the completion of the acquisition of Alpha Holdings’ 50% interest in the Company’s Marcellus joint venture, the Company accounted for its investment under the equity method of accounting.
The company is currently assessing the fair value of assets acquired and liabilities assumed. Immediately prior to the acquisition, the fair value of the existing equity in the Marcellus joint venture, based upon preliminary valuations, was approximately $245.0 million. The acquisition-date fair value of the existing equity was based on an income approach. The income approach calculated the present value of the future cash flows related to the natural gas properties as of the date of the transaction, utilizing a discount rate based upon market participant assumptions, natural gas strip prices as of the date of the transaction, and a decline curve consistent with our geographic peers. As we acquired the remaining ownership in the Marcellus joint venture we are required to remeasure our equity investment at fair value which will result in a non-recurring gain of approximately $195.2 million during the quarter ended March 31, 2014. On a preliminary basis and based on preliminary valuations performed to determine the fair value of the assets as of the acquisition date, the company anticipates the natural gas properties have fair value of approximately $320.0 million. The preliminary estimate of excess purchase price over net assets and liabilities assumed which is to be allocated to goodwill is approximately $365.0 million and will be deductible for tax purposes.
The acquisition consolidates the resources of the Company and the Marcellus joint venture which will enable the Company to efficiently develop the natural gas properties concurrently. The management team of the Company has historically also served as the management team of the joint venture, so the team is intimately familiar with the assets. These factors resulted in the aforementioned goodwill.
The following unaudited pro forma combined financial information presents the Company’s results as though the Company and the incremental 50% interest in our Marcellus joint venture had occurred at January 1, 2013.
The Company expects to complete the purchase price allocation during 2014 and may adjust the preliminary amounts set forth above to reflect the final valuation. This final valuation of the assets and liabilities could have a material impact on the pro forma information and preliminary purchase price allocation discussed above.
Income Taxes
At the date of IPO, Rice Energy owned 100% of Rice Drilling B and its subsidiaries. Rice Drilling B was a limited liability company not subject to federal income taxes before IPO. However, in connection with the closing of the IPO, as a result of our corporate reorganization, we became a corporation subject to federal income tax and, as such, our future income taxes will be dependent upon our future taxable income. The change in tax status would require the recognition of a deferred tax asset or liability for the initial temporary differences at the time of the change in status. The resulting deferred tax liability is approximately $145.1 million.
No current tax expense would result as of the date of the change in status. The recognition of the initial deferred tax liability will be recorded in equity at the date of IPO, but not in the financials as of December 31, 2013.
Unregistered Sales of Equity Securities
On January 29, 2014, pursuant to the Master Reorganization Agreement (the “Master Reorganization Agreement”) among Rice Energy Inc., Rice Drilling B, REA, Rice Holdings, Rice Partners, NGP Holdings, NGP RE Holdings, L.L.C., (“NGP RE Holdings”) NGP RE Holdings II, L.L.C. (“NGP RE II” and, together with NGP RE Holdings, “Natural Gas Partners”), Mr. Daniel J. Rice III, Rice Merger LLC (“Merger Sub”) and each of the persons holding incentive units representing interests in REA (collectively, the “Incentive Unitholders”) dated as of January 23, 2014, (i) (a) Rice Partners contributed a portion of its interests in REA to Rice Holdings, (b) Natural Gas Partners contributed its interests in REA to NGP Holdings and (c) the Incentive Unitholders contributed a portion of their incentive units to Rice Holdings and NGP Holdings, each in return for substantially similar incentive units in such entities; (ii) NGP Holdings, Rice Holdings and Mr. Daniel J. Rice III contributed their respective interests in Rice Appalachia to the Company in exchange for 43,452,550, 20,300,923 and 2,356,844 shares of Common Stock, respectively; (iii) Rice Partners contributed its remaining interest in Rice Appalachia to Rice Energy Inc. in exchange for 20,000,000 shares of Common Stock; (iv) the Incentive Unitholders contributed their remaining interests in Rice Appalachia to the Company in exchange for 160,831 shares of Common Stock, each of which were issued by the company in connection with the closing of the IPO. In connection with the IPO, in the first quarter of 2014, we recognized a non-cash compensation expense of $3.4 million.
In addition, on January 29, 2014, pursuant to the Agreement and Plan of Merger (the “Merger Agreement”) among the Company, Rice Drilling B and Merger Sub dated as of January 23, 2014, Rice Energy Inc. issued 1,728,852 shares of Common Stock to the members of Rice Drilling B (other than Rice Appalachia) for settlement of the restricted units.
Incentive Units
In connection with the IPO, in the first quarter of 2014, certain incentive units granted by NGP Holdings to certain members of management triggered the pre-determined payout criteria, resulting in a cash payment by NGP Holdings of $4.4 million. This resulted in additional non-cash compensation expense being recorded in the first quarter of 2014 by the Company.
Convertible Debentures and Warrants
In connection with the IPO, the convertible debentures and warrants of Rice Drilling B were amended to become convertible or exercisable for an aggregate 1,671,800 shares of common stock of Rice Energy. Through March 10, 2014, approximately $5.0 million of the convertible debentures have been converted into 433,073 shares of Rice Energy Inc. common stock. On February 28, 2014, the Company issued a call notice on the remaining convertible debentures, requiring a response by March 30, 2014. Amounts not converted by the response date will require payment by the Company of 100% of the principal amount plus a premium of 50%, which could result in additional costs of $1.0 million. As the principal amount of the convertible debentures outstanding has been reduced to less than $5.0 million, the Company is no longer required to maintain restricted cash. Through March 10, 2014, two warrants have been exercised in exchange for 1,728 shares of Rice Energy common stock.
Amendment to Senior Secured Revolving Credit Facility
On January 29, 2014, Rice Energy, as parent guarantor, and Rice Drilling B, as borrower, entered into an amendment (the “Sixth Amendment”) to the Second Amended and Restated Credit Agreement, dated as of April 25, 2013 with Wells Fargo Bank, N.A., as administrative agent and the lenders and other parties thereto (the “Second Amended and Restated Credit Agreement”). Rice Drilling B is a wholly-owned subsidiary of Rice Energy Inc. Among other things, the Sixth Amendment (i) added Rice Energy Inc. as a guarantor, (ii) increased the maximum commitment to $1.5 billion from $500.0 million, (iii) increased the borrowing base to $350.0 million from $200.0 million, (iv) lowered the interest rate on amounts borrowed, and (v) allowed for the corporate reorganization that was completed simultaneously with the closing of the IPO.
Subsequent to December 31, 2013, the Company issued additional letters of credit with Wells Fargo Bank, N.A. of $55.9 million (refer to Note 4 for further details on letters of credit as required by the Company’s natural gas marketer and pipeline).
Momentum Acquisition
On February 12, 2014, the Company’s wholly owned subsidiary, Rice Poseidon, entered into a Purchase Agreement with M3 to acquire certain gas gathering assets in eastern Washington and Greene Counties, Pennsylvania, for aggregate consideration of approximately $110.0 million in cash, subject to customary purchase price adjustments. Rice Energy expects the Momentum Acquisition to close in the second quarter of 2014, subject to customary closing conditions. The effective date for the Momentum Acquisition is March 1, 2014 and will be funded with proceeds received from our IPO.
The properties to be acquired in the Momentum Acquisition consist of a 28-mile, 6”-16” gathering system in eastern Washington County, Pennsylvania, and permits and rights of way in Washington and Greene Counties, Pennsylvania, necessary to construct an 18-mile, 30” gathering system connecting the northern system to the Texas Eastern pipeline. The northern system is supported by long-term contracts with acreage dedications covering approximately 20,000 acres from third parties. Once fully constructed, the acquired systems are expected to have an aggregate capacity of over 1 Bcf/d.
Subsequent events have been considered for disclosure and recognition through March 21, 2014, the same date the consolidated financial statements were available to be issued.
16.
Quarterly Financial Information (Unaudited)
The Company’s quarterly financial information for the years ended December 31, 2013 and 2012 is as follows (in thousands):
17.
Supplemental Information on Gas-Producing Activities (Unaudited)
Costs incurred for property acquisitions, exploration and development are as follows for Rice Drilling B (in thousands):
The following table presents the results of operations related to natural gas production for Rice Drilling B (in thousands):
Reserve quantity information is as follows for Rice Drilling B:
Extensions, Discoveries and Other Additions
The Company added 100,626 MMcf, 176,956 MMcf and 223,538 MMcf through its drilling program in the Marcellus Shale in 2013, 2012 and 2011, respectively.
Revision of Previous Estimates
In 2012, the Company had net negative revisions of 96,991 MMcf, as 32 proved undeveloped locations were removed from its estimate of reserves at December 31, 2011 due primarily to declines in natural gas pricing and changes to the Company’s drilling plans with regards to horizontal drilling.
The reserve quantity information is limited to reserves which had been evaluated as of December 31, 2013. Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves are expected to be recovered from new wells after substantial development costs are incurred. Netherland, Sewell and Associates, Inc. reviewed 100% of the total net gas proved reserves attributable to the Company’s interests and the Company’s Marcellus joint venture as of December 31, 2013 and 2012.
The information presented represents estimates of proved natural gas reserves based on evaluations prepared by the independent petroleum engineering firms of Netherland, Sewell and Associates, Inc. and Wright & Company in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. The Company’s independent reserve engineers were selected for their historical experience and geographic expertise in engineering unconventional resources. Since 1961, Netherland, Sewell and Associates, Inc. has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally. Wright & Company was founded in 1988 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers.
Certain information concerning the assumptions used in computing the standardized measure of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented. Future cash inflows are computed by applying the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through, respectively, to the period-end quantities of those reserves. Gas prices are held constant throughout the lives of the properties.
The assumptions used to compute estimated future net revenues do not necessarily reflect the Company’s expectations of actual revenues or costs, or their present worth. In addition, variations from the expected production rates also could result directly or indirectly from factors outside of the Company’s control, such as unintentional delays in development, changes in prices, or regulatory controls. The standardized measure calculation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, this could affect the amount of cash eventually realized.
Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved natural gas reserves at the end of the year, based on period-end costs and assuming continuation of existing economic conditions.
An annual discount rate of 10% was used to reflect the timing of the future net cash flows relating to proved natural gas reserves.
Information with respect to Rice Drilling B’s estimated discounted future net cash flows related to its proved natural gas reserves is as follows (in thousands):
(1)
Does not include the effects of income taxes on future revenues at December 31, 2013 and 2012 because as of December 31, 2013 and 2012, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, in connection with the closing of the IPO, as a result of the corporate reorganization, the Company became a corporation subject to federal income tax and, as such, its future income taxes will be dependent upon its future taxable income.
For 2013, the reserves for Rice Drilling B were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013, adjusted for energy content and a regional price differential. For 2013, this adjusted gas price was $3.91 per Mcf.
For 2012, the reserves for Rice Drilling B were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.86 per Mcf.
For 2011, the reserves for Rice Drilling B were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.36 per Mcf.
The following are the principal sources of changes in the standardized measure of discounted future net cash flows for Rice Drilling B (in thousands):
Gains on sales of interests in gas properties are not included in the information set forth above. We have also allocated certain general and administrative expenses to the Company’s results of operations as these expenses relate to production activities.
Costs incurred for property acquisitions, exploration and development related to the Company’s Marcellus joint venture (“the Marcellus joint venture”) are as follows (represents Rice Drilling B’s proportionate share, in thousands):
The following table presents Rice Drilling B’s share of the results of operations related to natural gas production of the Marcellus joint venture (represents Rice Drilling B’s proportionate share, in thousands):
Reserve quantity information is as follows for the Marcellus joint venture (represents Rice Drilling B’s proportionate share, in thousands):
Rice Drilling B’s 50% equity interest in the Marcellus joint venture added 19,812 MMcf, 98,119 MMcf and 58,800 MMcf through its drilling program in the Marcellus Shale in 2013, 2012 and 2011, respectively. In 2013, Rice Drilling B’s 50% equity interest in the Marcellus joint venture had net negative revisions of 26,803 MMcf due primarily to performance revisions. In 2012, Rice Drilling B’s 50% equity interest in the Marcellus joint venture had net negative revisions of 23,808 MMcf due primarily to declines in natural gas pricing.
Information with respect to Rice Drilling B’s share of the Marcellus joint venture’s estimated discounted future net cash flows related to its proved natural gas reserves is as follows (in thousands):
(1)
Does not include the effects of income taxes on future revenues at December 31, 2013 and 2012 because as of December 31, 2013 and 2012, the Company was a limited liability company not subject to entity-level taxation. Accordingly, no provision for federal or state corporate income taxes has been provided because taxable income was passed through to the Company’s equity holders. However, in connection with the closing of the IPO, as a result of the corporate reorganization, the Company became a corporation subject to federal income tax and, as such, its future income taxes will be dependent upon its future taxable income.
For 2013, the reserves for the Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013, adjusted for energy content and a regional price differential. For 2013, this adjusted gas price was $3.90 per Mcf.
For 2012, the reserves for the Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.84 per Mcf.
For 2011, the reserves for the Marcellus joint venture were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.34 per Mcf.
The following is for the Marcellus joint venture (represents Rice Drilling B’s proportionate share, in thousands), the principal sources of changes in the standardized measure of discounted future net cash flows:
Report of Independent Auditors
The Partners of
Alpha Shale Resources, LP
We have audited the accompanying financial statements of Alpha Shale Resources, LP, which comprise the balance sheets as of December 31, 2013 and 2012, and the related statements of operations, partners’ capital and cash flows for the years then ended, and the related notes to the financial statements.
Management’s Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Alpha Shale Resources, LP at December 31, 2013 and 2012, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.
Report of Other Auditors on December 31, 2011 Financial Statements Not Reissued
The financial statements of Alpha Shale Resources, LP for the year ended December 31, 2011 were audited by other auditors whose report dated April 20, 2012, expressed an unqualified opinion on those statements.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania
March 21, 2014
ALPHA SHALE RESOURCES, LP
BALANCE SHEETS
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
STATEMENTS OF OPERATIONS
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
STATEMENTS OF CASH FLOWS
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
STATEMENTS OF PARTNERS’ CAPITAL
YEARS ENDED DECEMBER 31, 2013, 2012 AND 2011
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2013 AND 2012
1.
Summary of Significant Accounting Policies and Related Matters
Organization and Operations
These financial statements present the activities for Alpha Shale Resources, LP (hereinafter referred to as the “Partnership”). The Partnership was organized as a limited partnership in accordance with the laws of the State of Delaware on February 3, 2010 (date of inception) through funding from its limited partners, Rice Drilling C, LLC (“Rice C”); a wholly-owned subsidiary of Rice Drilling B, LLC (“Rice B”) which in turn is a wholly-owned subsidiary of Rice Energy Inc. (“Rice Energy Inc.”); Foundation PA Coal Company, LLC (“PA Coal”), which is a wholly-owned indirect subsidiary of Alpha Natural Resources, Inc. (“ANR Holdings”); and its managing general partner, Alpha Shale Holdings, LLC (“Holdings”). According to the terms of the limited partnership agreement, revenues, costs and cash distributions of the Partnership are allocated 49.95% each to PA Coal and Rice and 0.10% to Holdings.
The Partnership is engaged primarily in the acquisition, exploration, development, production and sale of natural gas in the Marcellus Shale region of Southwestern Pennsylvania.
Use of Estimates
The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates and changes in these estimates are recorded when known.
Revenue Recognition
Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Partnership under contract with the Partnership’s natural gas marketer and only current customer. Pricing provisions are tied to the Platts Gas Daily market prices.
Cash
The Partnership maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed balance sheet amounts due to outstanding checks. The Partnership has no other accounts that are considered cash equivalents.
Accounts Receivable
Accounts receivable are primarily from the Partnership’s sole gas marketer. The Partnership extends credit to parties in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the party. There was no allowance recorded for any of the periods presented in the financial statements.
Natural Gas Properties
The Partnership uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in natural gas properties, to drill and equip exploratory wells that result in proved reserves are capitalized. Costs to drill exploratory wells that do not identify proved reserves as well as geological and geophysical costs and cost of carrying and retaining unproved properties are expensed.
Unproved natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Management determined that no impairment allowance was necessary as of December 31, 2013 and 2012. Capitalized costs of producing natural gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment not directly related to natural gas properties are depreciated over their estimated useful lives.
The Partnership assesses its proved natural gas properties for possible impairment on an annual basis, as events or changes in circumstances indicate that the carrying amount of an asset might not be recoverable. Management determined that no impairment allowance was necessary as of December 31, 2013 and 2012. During 2013, it was decided by the Operating Committee of the Partnership not to complete three vertical wells that had previously commenced drilling, as such an impairment charge of $0.1 million was recorded during the year ended December 31, 2013. There was no impairment charge during the year ended December 31, 2012. During 2011, it was decided by the Operating Committee of the Partnership not to complete two vertical wells that had previously commenced drilling. As such, an impairment charge of approximately $2.6 million was recorded during the year ended December 31, 2011.
Partnership estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Partnership adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization expense, as well as its impairment assessment of proved properties, a change in the Partnership’s estimated reserves could have a material effect on the Partnership’s net income or loss.
On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.
Interest
The Partnership capitalizes interest on expenditures for significant exploration and development projects while activities are in progress to bring the assets to their intended use. The following table summarizes the components of the Partnership’s interest incurred for the year indicated (in thousands):
Property and Other Equipment
Property and other equipment is recorded at cost and is being depreciated over estimated useful lives of five to fifteen years on a straight-line basis. Accumulated depreciation was $18 thousand and $9 thousand at December 31, 2013 and 2012, respectively. Depreciation expense was $9 thousand, $8 thousand and $1 thousand for the years ended December 31, 2013, 2012
and 2011, respectively, and is included in depreciation, depletion and amortization expense in the accompanying statements of operations.
Long-Lived Assets
Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. When required, impairment losses on assets to be held and used or disposed other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less selling costs.
Deferred Financing Costs
Deferred financing costs are amortized on a straight-line basis over the term of the related agreement. Accumulated amortization was $0.2 million and $15 thousand at December 31, 2013 and 2012, respectively. Amortization expense was $0.2 million, $15 thousand and $0 for the years ended December 31, 2013, 2012 and 2011, respectively. The annual amortization of deferred financing costs for years subsequent to December 31, 2013 is expected to be $0.3 million in each of the years through 2016 and $0.2 million in 2017.
Asset Retirement Obligations
The Partnership records the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. For gas properties, this is the period in which a gas well is acquired or drilled. The Partnership’s retirement obligations relate to the abandonment of gas-producing facilities and include costs to dismantle and relocate or dispose of the production platforms, gathering systems, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells and estimated remaining lives of those wells based on reserve estimates.
When a new liability is recorded, the Partnership capitalizes the costs of the liability by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the units of production basis.
Lease Obligations
The Partnership leases drilling rights under agreements which expire at various times. As of December 31, 2013, future minimum lease payments under these agreements expected to be paid during 2014 and 2015 are $0.1 million and $0.1 million, respectively, and are included as leasehold payables in the accompanying balance sheets.
Income Taxes
The Partnership is treated as a limited partnership for federal and state income tax purposes. Consequently, the Partnership is not subject to income taxes; instead its partners include the income in their tax returns.
Reclassifications
Certain reclassifications have been made to prior periods’ financial information related to accrued interest, other accrued liabilities and derivative liabilities to conform to the 2013 presentation.
2.
Capitalized Costs Relating to Natural Gas-Producing Activities
Proved and unproved capitalized costs related to the Partnership’s natural gas-producing activities are as follows (in thousands):
The Partnership had long-term debt outstanding as follows (in thousands):
Wells Fargo Credit Facility
On September 7, 2012, the Partnership entered into a credit agreement (“Wells Fargo Credit Facility”) with Wells Fargo Bank, N.A. (“Wells Fargo”). The maximum credit amount allowed under the promissory note agreement is $200.0 million, payable at maturity with interest only due in monthly installments at the higher of the prime rate, the federal funds rate plus 0.5% or the adjusted LIBOR plus 1%; all unpaid balances are due September 7, 2017; secured by substantially all assets of the Partnership. The weighted average interest rate was 2.42% as of December 31, 2013. As of December 31, 2013, the Partnership issued letters of credit of $10.4 million with Wells Fargo as required by the Partnership’s natural gas marketer. The borrowing base as of December 31, 2013 was $145.0 million with approximately $59.2 million undrawn at that date. This credit facility was repaid using proceeds from the Rice Energy Inc. IPO during the first quarter of 2014.
The Wells Fargo Credit Facility provides for borrowings to be used for the purpose of funding capital expenditures related to the Partnership’s drilling program, providing working capital for lease acquisitions, exploration and production operations, and development (including the drilling and completion of producing wells), and for general business purposes, including fees and expenses. The Wells Fargo Credit Facility is subject to a maximum borrowing base equal to the maximum value, for credit purposes, of the subject properties as determined by Wells Fargo in accordance with its customary lending practices. The borrowing base is determined by the lenders on a quarterly basis and such determination is primarily based upon the value of the Partnership’s proved developed reserves. If the lenders were to decrease the borrowing base below the amounts outstanding under the facility, the Partnership would have to repay these amounts within 30 days, repay these amounts in six monthly installments, or add sufficient collateral value.
The Wells Fargo Credit Facility is subject to certain covenants which are ordinary to such credit facilities and include, among other things, minimum financial ratios, restrictions as to additional debt and changes to the Partnership’s structure. The Partnership was in compliance with such covenants and ratios as of December 31, 2013.
Interest paid in cash was $1.5 million and $0.1 million for the years ended December 31, 2013 and 2012, respectively. See Note 1 for information on capitalized interest.
4.
Fair Value of Financial Instruments
The Partnership determines fair value on a recurring basis for its amounts related to its derivative instruments as the amounts are required to be recorded at fair value each reporting period. Fair value is based on quoted market prices, where available. If quoted market prices are not available, fair value is based upon models that use as inputs market-based parameters, including but not limited to forward curves, discount rates, broker quotes, volatilities, and nonperformance risk.
The Partnership has categorized its fair value measurements into a three-level fair value hierarchy, based on the priority of the inputs to the valuation technique. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets and liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). All of the Partnership’s fair value measurements are included in Level 2. Since the adoption of fair value accounting, the Partnership has not made any changes to its classification of financial instruments in each category.
Items included in Level 2 are valued using management’s best estimate of fair value corroborated by third-party quotes.
The following items were measured at fair value on a recurring basis during the period (refer to Note 7 for details relating to derivative instruments) (in thousands):
The carrying amount of cash, receivables and accounts payable approximate their fair value due to the short-term nature of such instruments.
The estimated fair value of long-term debt on the balance sheet at December 31, 2012 is shown in the table below (refer to Note 3 for details relating to the borrowing arrangements (in thousands). The fair value was estimated using Level 3 inputs based on rates reflective of the remaining maturity as well as the Partnership’s financial position.
5.
Asset Retirement Obligations
The Partnership is subject to certain legal requirements which result in recognition of a liability related to the obligation to incur future plugging and abandonment costs. The Partnership records a liability for such asset retirement obligations and capitalizes a corresponding amount for asset retirement costs. The liability is estimated using the present value of expected future cash flows, adjusted for inflation and discounted at the Partnership’s credit adjusted risk-free rate. No wells were plugged or abandoned during 2012, nor were there any changes to assumptions. A reconciliation of the beginning and ending aggregate carrying amount of asset retirement obligations for the years ended December 31, 2013, 2012 and 2011 is as follows (in thousands):
The Partnership consists of three partners: Holdings, which is the managing general partner, and PA Coal and Rice C, the limited partners. The Partnership authorized and issued 10,000 units during 2010. In February 2010, Holdings contributed $6 thousand for 10 units, or a 0.10% ownership, and PA Coal and Rice each contributed $3.0 million for 4,995 shares, or 49.95% ownership each. In 2011, 2012 and 2013 the managing partner contributed an additional $30 thousand, $20 thousand, and $39 thousand, respectively, and the limited partners contributed an additional $29.6 million, $20.0 million and $38.6 million, respectively.
Since inception, the three partners have continued to make additional contributions into the Partnership, in accordance with ownership percentages, and no additional units were issued as depicted on the statements of changes in partners’ capital.
7.
Derivative Instruments
The Partnership uses derivative commodity instruments that are placed with major financial institutions whose creditworthiness is regularly monitored. Our derivative counterparties share in the Credit Agreement collateral. The Partnership’s derivative commodity instruments have not been designated as hedges for accounting purposes; therefore, all gains and losses were recognized in income currently. As of December 31, 2013, the Partnership entered into derivative instruments with Wells Fargo Bank, N.A. and Bank of Montreal fixing the price it receives for natural gas through December 31, 2017, as summarized in the following table:
The following is a summary of the Partnership’s derivative instruments, which are recorded in the balance sheet as of December 31, 2013 and 2012 (in thousands):
The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value:
Both realized and unrealized gains and losses are recorded as a gain or loss on derivatives in the consolidated statement of operations under other income/expense. Unrealized losses were $1.3 million and $0.1 million for the years ended December 31, 2013 and 2012, respectively. Realized gains related to contract settlements were $4.6 million and $0.1 million for the years ended December 31, 2013 and 2012, respectively. The Partnership did not have any derivative instruments as of December 31, 2011.
8.
Commitments and Contingencies
The Partnership is involved in various litigation matters arising in the normal course of business. Management is not aware of any actions that are expected to have a material adverse effect on its financial position or results of operations.
The Partnership has drilling commitments which management expects to meet in the ordinary course of business.
9.
Related-Party Transactions
During the years ended December 31, 2013 and 2012, the Partnership was billed for management services provided in the amount of $2.1 million and $1.3 million, respectively, which is included with general and administrative expenses on the statements of operations. As of December 31, 2013 and 2012, $2.0 million and $8.5 million, respectively, of costs were due to related entities and recorded as payable to affiliate on the balance sheets. Included in the 2013 amount are management service fees as described above as well as fees for gathering and transportation incurred by the Partnership that were billed to related parties. Included in the 2012 amount is $6.0 million relating to capitalized costs that were approved to be contributed from related entities.
During 2011, management services were provided by related entities; however, the partners agreed to waive charging a fee to the Partnership for these services for 2011.
Payments totaling $1.2 million, $0.5 million and $0.4 million were made during the years ended December 31, 2013, 2012 and 2011 respectively to Geological Engineering Services, Inc. (“GES”) in respect of consultancy services. GES is a drilling and completion engineering consulting company specializing in unconventional reservoirs like the Marcellus Shale. John P. LaVelle, Rice Energy’s Vice President of Drilling, served as president of GES from February 1994 until February 2010. There were no amounts outstanding between the Partnership and GES as of any period presented.
Transaction Agreement
On January 29, 2014, pursuant to the Transaction Agreement between Rice Energy Inc., Rice C and Alpha Holdings dated as of December 6, 2013 (the “Transaction Agreement”), Rice Energy Inc. completed their acquisition of Alpha Holdings’ 50% interest in the Partnership in exchange for total consideration of $300 million, consisting of $100 million of cash and the issuance to Alpha Holdings of 9,523,810 shares of Rice Energy Inc. common stock.
Subsequent events have been considered for disclosure and recognition through March 21, 2014, the same date the financial statements were available to be issued.
11.
Supplemental Information on Gas-Producing Activities (Unaudited)
Costs incurred for property acquisitions, exploration and development for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands):
The following table presents the results of operations related to natural gas production (in thousands):
Reserve quantity information for the years ended December 31, 2013, 2012 and 2011 are as follows (in thousands):
The Partnership added 39,623 MMcf, 196,238 MMcf and 117,600 MMcf through its drilling program in the Marcellus Shale in 2013, 2012 and 2011, respectively. In 2013, the Partnership had net negative revisions of 53,605 MMcf due primarily to performance revisions. In 2012, the Partnership had net negative revisions of 47,616 MMcf due primarily to declines in natural gas pricing.
Information with respect to estimated discounted future net cash flows related to its proved natural gas reserves as of December 31, is as follows (in thousands):
For 2013, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2013, adjusted for energy content and a regional price differential. For 2013, this adjusted gas price was $3.90 per Mcf.
For 2012, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2012, adjusted for energy content and a regional price differential. For 2012, this adjusted gas price was $2.84 per Mcf.
For 2011, the reserves were computed using unweighted arithmetic averages of the closing prices on the first day of each month during 2011, adjusted for energy content and a regional price differential. For 2011, this adjusted gas price was $4.34 per Mcf.
The following is the principal sources of changes in the standardized measure of discounted future net cash flows (in thousands):
INDEPENDENT AUDITORS’ REPORT
To the Partners of
Alpha Shale Resources, LP
Canonsburg, Pennsylvania
We have audited the accompanying balance sheet of Alpha Shale Resources, LP (Partnership) as of December 31, 2011 and for the year then ended and the related statements of operations, changes in partners’ capital and cash flows. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Alpha Shale Resources, LP as of December 31, 2011 and for the year then ended and the results of its operations and its cash flows, in conformity with accounting principles generally accepted in the United States of America.
/s/ Schneider Downs & Co., Inc.
Pittsburgh, Pennsylvania
April 20, 2012
ALPHA SHALE RESOURCES, LP
BALANCE SHEET
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2011
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2011
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
STATEMENT OF CHANGES IN PARTNERS’ CAPITAL
FOR THE YEAR ENDED DECEMBER 31, 2011
See accompanying Notes to Financial Statements.
ALPHA SHALE RESOURCES, LP
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2011
1.
Organization and Operations
These financial statements present the activities for Alpha Shale Resources, LP (hereinafter referred to as the Partnership). The Partnership was organized as a limited partnership in accordance with the laws of the State of Delaware on February 3, 2010 (date of inception) through funding from its limited partners, Foundation PA Coal Company, LLC (Alpha Holdings), and Rice Drilling C, LLC (Rice Drilling C) and its managing general partner, Alpha Shale Holdings, LLC (Holdings). According to the terms of the limited partnership agreement, revenues, costs and cash distributions of the Partnership are allocated 49.95% each to Alpha Holdings and Rice Drilling C and 0.10% to Holdings.
Alpha is engaged primarily in the acquisition, exploration, development, production and sale of natural gas. Drilling is engaged in the tendering of natural gas wells in the Marcellus Shale region of Southwestern Pennsylvania. The Partnership sells its natural gas products solely to a natural gas marketing customer, which accounts for 100% of its accounts receivable as of December 31, 2011, and 100% of its sales for the year ended December 31, 2011. Natural gas sales included in the statement of operations consist of sales for one horizontal well, which was in production from May 2011 through December 31, 2011.
2.
Summary of Significant Accounting Policies
A summary of significant accounting policies consistently applied by management in the preparation of the accompanying financial statements follows:
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Natural Gas Properties. The Partnership uses the successful efforts method of accounting for gas-producing activities. Costs to acquire mineral interests in natural gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells and related asset retirement costs are capitalized. Depletion is based on cost less estimated salvage value using the unit-of-production method. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of geological, geophysical, engineering and economic data. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.
Partnership estimates of proved reserves are based on quantities of natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. The petroleum engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, the Partnership adjusts natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent the Partnership’s most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect the Partnership’s depreciation, depletion and amortization expense, a change in the Partnership’s estimated reserves could have a material effect on the Partnership’s net income.
Unproved natural gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Management determined that no impairment allowance was necessary at December 31, 2011. Unproved natural gas properties approximated $3.8 million at December 31, 2011. Capitalized costs of producing natural gas properties, after considering estimated residual salvage values, are depreciated and depleted by the unit-of-production method. Support equipment and other property and equipment are depreciated over their estimated useful lives. Wells in progress approximated $27.8 million at December 31, 2011.
The Partnership assesses its proved natural gas properties for possible impairment on an annual basis, as events or changes in circumstances indicate that the carrying amount of an asset might not be recoverable. During 2011, it was decided by the
Operating Committee of the Partnership not to complete two vertical wells that had previously been drilled. As such, an impairment charge of approximately $2.6 million was recorded during the period ended December 31, 2011.
On the sale of an entire interest in an unproved property for cash or cash equivalent, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Revenue Recognition. Sales of natural gas are recognized when natural gas has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Partnership under contract with the Partnership’s natural gas marketer and only current customer. All of the Partnership contracts’ pricing provisions are tied to Platts Gas Daily market prices. As a result, the Partnership’s revenue from the sale of natural gas will suffer if market prices decline and benefit if they increase. The Partnership believes that the pricing provisions of its natural gas contracts are customary in the industry.
Cash and Cash Equivalents. The Partnership maintains cash that might exceed federally insured amounts at times. The Partnership considers all items purchased with a maturity of three months or less and all interest-bearing money market funds to be cash and cash equivalents.
Accounts Receivable. The Partnership performs ongoing credit evaluations of its customer and does not require collateral. Provisions are made for estimated uncollectible trade accounts receivable. The Partnership’s estimate is based on historical collection experience, a review of current status of trade receivables and judgment. Decisions to charge-off receivables are based on management’s judgment after consideration of facts and circumstances surrounding potential uncollectible accounts. Management determined that no allowance was necessary at December 31, 2011.
Asset Retirement Obligations. The Partnership accounts for its asset retirement obligations, plugging costs, as required by the Asset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (Codification or ASC), which requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. For the Partnership, asset retirement obligations primarily relate to the abandonment of natural gas-producing facilities and are accreted over the estimated life of the related asset, for the change in present value. The initial capitalized costs are depleted over the useful lives of the related asset, through charges to depreciation, depletion and amortization expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from revisions of estimated inflation rates, escalating retirement costs and changes in the estimated timing of settling asset retirement obligations.
The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted, risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulations enact new plugging and abandonment requirements. The Partnership has a $25 thousand bond deposit, legally restricted for purposes of settling asset retirement obligations in the Commonwealth of Pennsylvania. This bond deposit is included in prepaid and other assets.
A reconciliation of the Partnership’s liability for well plugging and abandonment costs as of December 31, 2011 is as follows (in thousands):
The accretion expense relative to the asset retirement obligations is included on the statements of operations under the caption depreciation, depletion and amortization.
Income Taxes. The Partnership is organized as a limited partnership and is not subject to federal or state income taxes. Accordingly, no provision has been made for current or deferred income taxes in these financial statements. The taxable income of the Partnership is included in the tax return of the individual partners. In addition, the Partnership has not identified any
material uncertain tax positions requiring an accrual or disclosure in the financial statements. The Partnership accrues interest and penalties related to unrecognized tax benefits in income tax expense. Additionally, the Partnership’s U.S. Federal income tax return filed for 2010 remains subject to examination by the Internal Revenue Service (IRS).
Recent Accounting Pronouncements. In January 2010, the FASB issued the Accounting Standards Update (ASU), Fair Value Measurements Disclosures, to require new disclosures for fair value measurements and to provide clarification for existing disclosure requirements. More specifically, this update will require (1) an entity to disclose separately the amounts of significant transfers in and out of Levels I and 2 fair value measurements and to describe the reasons for the transfers; and (2) information about purchases, sales, issuances and settlements to be presented separately on a gross basis rather than net, in the reconciliation for fair value measurements using significant unobservable inputs (Level 3 inputs). The ASU clarifies existing disclosure requirements for the level of disaggregation used for classes of assets and liabilities measured at fair value and requires disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements using Level 2 and Level 3 inputs. The adoption of the ASU by the Partnership did not materially impact or expand its financial statement footnote disclosures.
3. Natural Gas Properties
Natural gas properties at December 31, 2011 consist of the following (in thousands):
Included in proved and producing are the estimated costs associated with the Partnership’s asset retirement obligations discussed in Note 2, which approximated $0.3 million at December 31, 2011.
4. Partners’ Capital
The Partnership consists of three partners: Holdings, which is the managing general partner, and Alpha Holdings and Rice Drilling C, the limited partners. The Partnership authorized and issued 10,000 units during 2010. In February 2010, Holdings contributed $6 thousand for 10 units, or a 0.10% ownership, and Alpha Holdings and Rice Drilling C each contributed $3.0 million for 4,995 shares, or 49.95% ownership each.
In November 2010, the Partnership had an additional capital call amounting to $4.0 million, of which $4 thousand was contributed by Holdings; and Alpha Holdings and Rice Drilling C contributed $2.0 million each, in line with ownership percentages; and no additional units were issued.
During 2011, the three partners continued to make contributions into Alpha, in line with ownership percentages, and no additional units were issued as depicted on the Statement of Changes in Partners’ Capital.
5. Contingencies
The Partnership is involved in various legal proceedings arising out of the normal conduct of its business. In the opinion of management, the ultimate resolution of such matters will not have a material effect on the financial position or results of operations of the Partnership.
The Partnership is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Partnership has established procedures for the ongoing evaluation of its operations, to identify potential environmental exposures and to comply with regulatory policies and procedures.
The Partnership accounts for environmental contingencies in accordance with the Contingencies topic of the FASB Codification. Environmental expenditures that relate to current operations are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessment and/or cleanup is probable, and the costs can be
reasonably estimated. The Partnership maintains insurance that may cover in whole or in part certain environmental expenditures. At December 31, 2011, the Partnership had no environmental contingencies requiring specific disclosure or accrual.
6. Related-Party Activity
During 2011, management services were provided by related entities to the Partnership; however, the partners agreed to waive charging a fee to Alpha for these services for 2011.
During the year ended December 31, 2011, the Partnership incurred expenses relative to the development and production of natural gas properties with related parties amounting to approximately $0.5 million.
Amounts due to partners and related parties approximated $33 thousand at December 31, 2011.
7. Fair Value Measurements
Fair value measurement requires disclosures that categorize assets and liabilities measured at fair value into one of three different levels depending on the assumptions (i.e., inputs) used in the valuation. Level 1 provides the most reliable measure of fair value, while Level 3 generally requires significant management judgment: Financial assets and liabilities are classified in their entirety based on the lowest level of input significant to the fair value measurement. The fair value hierarchy is defined as follows:
Level 1-Valuations are based on unadjusted quoted prices in active markets for identical assets or liabilities.
Level 2-Valuations are based on quoted prices for similar assets or liabilities in active markets, or quoted prices in markets that are not active for which significant inputs are observable, either directly or indirectly.
Level 3-Valuations are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Inputs reflect management’s best estimate of what market participants would use in valuing the asset or liability at the measurement date.
At December 31, 2011, the Partnership’s financial instruments consist primarily of cash, accounts receivable and accounts payable. The carrying amount of cash, receivables and accounts payable approximate their fair value due to the short-term nature of such instruments.
The Partnership reviews long-lived assets, including natural gas properties, for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets might not be recoverable. If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the asset’s carrying value, it is impaired and the carrying value is reduced to the asset’s current fair value. These fair value measurements fell within Level 3 of the fair value hierarchy. During 2011, the Partnership determined that certain natural gas properties were impaired, resulting in an impairment charge of $2.6 million. The impairment charge reduced the remaining carrying value of these properties to their aggregate fair value of approximately $0 at December 31, 2011.
8.
Subsequent Events
Subsequent events are defined as events or transactions that occur after the balance sheet date, but before the financial statements are issued or are available to be issued. Management has evaluated subsequent events through April 20, 2012, the date on which the financial statements were available to be issued and noted that there was an additional capital contribution in February 2012 in the amount of $12.0 million.
Independent Accountants’ Compilation Report
To the Members of
Countrywide Energy Services, LLC
We have compiled the accompanying balance sheet of Countrywide Energy Services, LLC, a Pennsylvania limited liability company (the “Company”), as of December 31, 2013, and the related statements of operations, members’ capital, and cash flows for the year then ended. We have not audited or reviewed the accompanying financial statements and, accordingly, do not express an opinion or provide any assurance about whether the financial statements are in accordance with accounting principles generally accepted in the United States of America.
Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America and for designing, implementing, and maintaining internal control relevant to the preparation and fair presentation of the financial statements.
Our responsibility is to conduct the compilation in accordance with Statements on Standards for Accounting and Review Services issued by the American Institute of Certified Public Accountants. The objective of a compilation is to assist management in presenting financial information in the form of financial statements without undertaking to obtain or provide any assurance that there are no material modifications that should be made to the financial statements.
/s/ Grossman Yanak & Ford LLP
Pittsburgh, Pennsylvania
March 3, 2014
Independent Auditors’ Report
To the Members of
Countrywide Energy Services, LLC
We have audited the accompanying financial statements of Countrywide Energy Services, LLC, a Pennsylvania limited liability company, (the “Company”), which comprise the balance sheet as of December 31, 2012, and the statements of operations, members’ capital, and cash flows for the year ended December 31, 2012 and the period from May 9, 2011 to December 31, 2011, and the related notes to the financial statements.
Management's Responsibility for the Financial Statements
Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.
Auditors' Responsibility
Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Countrywide Energy Services, LLC as of December 31, 2012, and the results of its operations and its cash flows for the year ended December 31, 2012 and the period from May 9, 2011 to December 31, 2011 in accordance with accounting principles generally accepted in the United States of America.
/s/ Grossman Yanak & Ford LLP
Pittsburgh, Pennsylvania
February 20, 2013
Countrywide Energy Services, LLC
Balance Sheets
December 31, 2013 and 2012
See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.
Countrywide Energy Services, LLC
Statements of Operations
For the Years Ended December 31, 2013 (Unaudited) and 2012
and for the Period from May 9, 2011 to December 31, 2011
See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.
Countrywide Energy Services, LLC
Statements of Cash Flows
For the Years Ended December 31, 2013 (Unaudited) and 2012
and for the Period from May 9, 2011 to December 31, 2011
Supplemental disclosure of noncash investing and financing activities:
During the year ended December 31, 2013, the Company financed equipment acquisitions of $0.2 million with capital leases. Additionally, equipment was sold in exchange for cash of $0.4 million and a note receivable of $1.4 million (see Note 2).
Also as of December 31, 2013, distributions of $0.1 million were included in distributions payable.
During the year ended December 31, 2012, the Company financed equipment acquisitions of $0.2 million with capital leases.
During the period from May 9, 2011 to December 31, 2011, the Company financed equipment acquisitions of $2.1 million with a note payable of $0.3 million and capital leases of $1.8 million. Additionally, equipment purchases of $0.3 million were unpaid and included in accounts payable as of December 31, 2011.
See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.
Countrywide Energy Services, LLC
Statements of Members’ Capital
For the Years Ended December 31, 2013 (Unaudited) and 2012
and for the Period from May 9, 2011 to December 31, 2011
See accompanying Notes to Financial Statements, Independent Accountants’ Compilation Report and Independent Auditors’ Report.
Countrywide Energy Services, LLC
Notes to Financial Statements
1.
Summary of Significant Accounting Policies and Related Matters
Organization and Activity - The Company was organized as a Pennsylvania limited liability company on January 21, 2010. The Company offers a wide-range of roustabout and oil field services to enterprises that are exploring and extracting Pennsylvania’s Marcellus Shale natural gas. These services include logistics, site preparation, maintenance, water transfer, land reclamation and production services.
Prior to the Company’s amended and restated operating agreement dated May 9, 2011, the Company had a sole member. Effective May 9, 2011, a 50% membership interest in the Company was purchased by Rice Drilling B LLC (“Rice Drilling B”).
Basis of Accounting - The Company maintains its accounting records on the accrual basis of accounting. Revenues are recognized for services provided or equipment on site based upon daily rates as specified in master service agreements with customers. Expenses are recognized as incurred.
The members of the Company decided that operations would be discontinued in the summer of 2013 as a result of the departure of the Company’s president. Subsequent operating activity has been limited to finishing work on outstanding contracts and selling the operating assets of the Company to an unrelated third party in exchange for cash and an installment note (see Note 2). The Company is in the process of converting the remaining assets to cash and satisfying its obligations. Remaining cash as well as the installment note will be distributed to Rice Drilling B and the other member in 2014 so that the Company can be dissolved. While the Company is in the process of liquidating, the financial statements have not been presented on the liquidation basis. However, the differences between the financial statements as presented and under the liquidation basis would not be significant.
Use of Estimates - The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.
Comprehensive Income - Comprehensive income consists of net income plus changes in other equity accounts. The Company had no comprehensive income beyond its net income for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011.
Cash - The Company maintains cash at financial institutions which may at times exceed federally insured amounts and which may at times significantly exceed the balance sheets amounts due to outstanding checks.
Accounts Receivable - The Company regularly extended credit to customers for services provided in the normal course of business based upon management’s assessment of their creditworthiness. A valuation allowance is provided for those accounts for which collection is estimated as doubtful; uncollectible accounts are written off and charged against the allowance. Increases in the allowance are charged to general and administrative expenses. Accounts are judged to be delinquent principally based on contractual terms. In estimating the allowance, management considers, among other things, how recently and how frequently payments have been received and the financial position of the customer. While these estimates incorporated management’s assessment at December 31, 2013 and 2012, it is at least reasonably possible that the allowances will be further revised in the near term and actual results could differ from these estimates.
Equipment - Equipment is recorded at cost. Expenditures for major renewals and betterments that extend the useful lives of equipment are capitalized. Expenditures for maintenance and repairs are charged to expense as incurred. Provision for depreciation is computed using the straight-line method based on the estimated useful lives of the assets which range from two to ten years. Equipment under capital lease obligations is depreciated on the straight-line method over the shorter of the lease term or the estimated useful life of the equipment.
The carrying values of long-lived assets, which are limited to equipment, are evaluated periodically in relation to the operating performance of the underlying assets. Adjustments are made if the sum of expected future cash flows is less than book value and, if required, such adjustments would be measured based on discounted cash flows.
See Independent Accountants’ Compilation Report and Independent Auditors’ Report.
Income Taxes - The Company is treated as a partnership for federal and state income tax purposes. Consequently, the Company is not subject to income taxes; instead its members include the income in their tax returns.
Subsequent Events - Management has evaluated subsequent events for recognition and disclosure purposes through March 3, 2014, the date the financial statements were available to be issued.
During 2013, the Company sold equipment in exchange for $0.4 million cash and a $1.4 million note receivable. Payments on this note are due in monthly installments of $42 thousand, including interest at 5%, beginning March 1, 2014 with final payment on February 1, 2017. The note is secured by the equipment. Installments on this note subsequent to December 31, 2013 are expected to be as follows (in thousands):
Equipment consists of the following as of December 31, 2013 and 2012 (in thousands):
Depreciation expense was $0.8 million, $0.9 million and $0.3 million for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively. The cost of equipment held under capital leases as of December 31, 2013 and 2012 was $0.1 million and $1.8 million, respectively. Accumulated depreciation of equipment held under capital leases was $16 thousand and $0.5 million as of December 31, 2013 and 2012, respectively.
See Independent Accountants’ Compilation Report and Independent Auditors’ Report.
Notes payable consist of the following as of December 31, 2012 (in thousands):
All notes payable were repaid during 2013.
As of December 31, 2013, the Company has vehicles under capital leases with remaining obligations of $30 thousand. Subsequent to December 31, 2013, the Company purchased the vehicles for approximately $31 thousand and the lease agreements were terminated.
The Company also leased a garage and the surrounding land under an operating lease which was transferred to a third party in November 2013. Rent expense for this lease was $33 thousand, $31 thousand and $20 thousand for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively.
Additionally, the Company rented equipment and vehicles under various short term arrangements. Rental expense for these items was approximately $0.4 million, $0.9 million and $1.2 million for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively.
The Company provided services to related companies (including Rice Drilling B, one of its investees, and one of its subcontractors) which accounted for approximately 91%, 85% and 60% of revenues for the years ended December 31, 2013 and 2012 and for the period from May 9, 2011 to December 31, 2011, respectively. Two additional customers accounted for approximately 26% of the Company’s revenues for the period from May 9, 2011 to December 31, 2011. Receivables from related companies accounted for 82%, and 98% of accounts receivable as of December 31, 2013 and 2012, respectively.
See Independent Accountants’ Compilation Report and Independent Auditors’ Report.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not Applicable.
Item 9A.
Item 9A. Controls and Procedures
Material Weakness in Internal Control over Financial Reporting
Prior to the completion of our IPO, we were a private company with limited accounting personnel to adequately execute our accounting processes and other supervisory resources with which to address our internal control over financial reporting. In addition, our Marcellus joint venture historically relied on our accounting personnel for its accounting processes. We and our Marcellus joint venture had not maintained effective control environments in that the design and execution of our controls had not consistently resulted in effective review and supervision by individuals with financial reporting oversight roles. The lack of adequate staffing levels resulted in insufficient time spent on review and approval of certain information used to prepare the financial statements of us and our Marcellus joint venture. We concluded that these control deficiencies constituted a material weakness in our control environment and in the control environment of our Marcellus joint venture. A material weakness is a control deficiency, or a combination of control deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.
In 2011, we and our Marcellus joint venture did not maintain effective controls to ensure proper close processes, formal account reconciliations and technical accounting matter resolution and documentation. In 2012, we and our Marcellus joint venture did not maintain effective controls to ensure proper staffing and supervisory review. For each of these periods, effective controls were not adequately designed or consistently operating to ensure that key computations were properly reviewed before the amounts were recorded in our accounting records. The above identified control deficiencies resulted in audit adjustments to our consolidated financial statements during 2011 and 2012.
To address these control deficiencies, we have implemented additional analysis and reconciliation procedures and increased the levels of review and approval. In addition, we have hired 20 additional accounting and financial reporting staff to complement our historical accounting staff of four individuals as of December 31, 2012. These hires were made to allow for additional preparation and review time during our monthly accounting close process. Additionally, we have begun taking steps to comprehensively document and analyze our system of internal control over financial reporting in preparation for our first management report on internal control over financial reporting required in connection with our annual report for the year ended December 31, 2014. Although remediation efforts are still in progress, we believe the implementation of these changes has substantially improved our control environment as evidenced by the timely filing of this Annual Report and a significant decrease in audit adjustments as compared to prior periods. None of these audit adjustments were deemed material.
Due to the recent implementation of these changes to our control environment, management continues to evaluate the design and effectiveness of these control changes in connection with its ongoing evaluation, documentation, review, formalization and testing of our internal control environment over the remainder of 2014. We will not complete our review until the second half of 2014 and we cannot predict the outcome of our review at this time. Based upon the status of our review, we and our independent auditors have concluded that the material weakness had not been fully remediated as of December 31, 2013.
During the course of the review, we may identify additional control deficiencies, which could give rise to significant deficiencies and other material weaknesses in addition to the material weakness previously identified. Our remediation efforts may not enable us to remedy or avoid material weaknesses or significant deficiencies in the future.
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2013. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. In light of the previously identified material weakness described above, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level as of December 31, 2013. Notwithstanding the existence of the material weakness, management concluded that the financial statements and other financial information included in this Annual Report on Form 10-K presents fairly, in all material respects, the financial condition, results of operations and cash flows for all periods presented.
Management’s Report on Internal Control Over Financial Reporting
This Annual Report on Form 10-K does not include a report on management’s assessment regarding internal control over financial reporting due to a transition period established by the rules of the SEC for newly public companies.
Attestation Report of the Registered Public Accounting Firm
This Annual Report on Form 10-K does not include an attestation report of our independent registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies. Further, our independent registered public accounting firm will not be required to formally attest to the effectiveness of our internal controls over financial reporting for as long as we are an “emerging growth company” pursuant to the provisions of the JOBS Act.
Changes in Internal Control over Financial Reporting
As described above, there were changes in our system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2013 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Item 9B. Other Information
Not Applicable.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The following table sets forth the names, ages and titles of our directors and executive officers as of March 10, 2014.
Name
Age
Position with Rice Energy
Daniel J. Rice IV
Director, Chief Executive Officer
Toby Z. Rice
Director, President and Chief Operating Officer
Derek A. Rice
Vice President of Exploration & Geology
Grayson T. Lisenby
Vice President and Chief Financial Officer
James W. Rogers
Vice President, Chief Accounting & Administrative Officer, Treasurer
William E. Jordan
Vice President, General Counsel and Corporate Secretary
Robert F. Vagt
Director (Chairman)
Daniel J. Rice III
Director
Scott A. Gieselman
Director
Chris G. Carter
Director
James W. Christmas
Director
Kevin S. Crutchfield
Director
Set forth below is the description of the background of our directors and executive officers. References to positions held at Rice Energy include positions held at Rice Drilling B prior to our corporate reorganization.
Daniel J. Rice IV has served as a member of our board of directors and our Chief Executive Officer since October 2013. Mr. Rice joined Rice Partners in October 2008 and served as the Vice President and Chief Financial Officer of Rice Energy from October 2008 through October 2012. From October 2012 through September 2013, Mr. Rice served as the Chief Operating Officer of Rice Energy. Prior to joining Rice Energy, he served as an investment banker for Tudor Pickering Holt & Co., LLC, an integrated energy investment bank in Houston, Texas, from February 2008 to October 2008. Prior to his employment at Tudor Pickering Holt, he served as a senior analyst of corporate planning for Transocean Inc., responsible for mergers and acquisitions and business development, from March 2005 to February 2008. He was appointed Chief Executive Officer in October 2013. Daniel J. Rice IV holds a BS in Finance from Bryant University. He is the son of Daniel J. Rice III and the brother of Toby Rice and Derek Rice.
The board believes that Mr. Rice’s considerable financial and operational experience brings important and valuable skills to the board of directors.
Toby Z. Rice has served as our President and Chief Operating Officer since October 2013. Mr. Rice joined Rice Partners in February 2007 and later joined Rice Energy as its President and Chief Executive Officer when it was formed in February 2008 through September 2013. He has also served as a Manager of Rice Energy since its formation. From September 2005 until March 2008, he also served as founder and president of ZFT LLC, a consulting company specializing in the application of new hydraulic fracturing technologies for unconventional shale and tight sandstone reservoirs. Toby Rice was appointed to his current role in October 2013. He holds a BS in Chemistry from Rollins College and is the son of Daniel J. Rice III and the brother of Daniel J. Rice IV and Derek Rice.
The board believes that Mr. Rice’s considerable operational experience brings important and valuable skills to the board of directors.
Derek A. Rice has served as Rice Energy’s Vice President of Exploration & Geology since 2009 and is responsible for geologic and geophysical interpretations. Prior to joining Rice Partners and Rice Energy in August 2009, from June 2007 to September 2007 and from June 2008 until September 2008, he worked as a wellbore geologist for a large oilfield service company, where he analyzed the Marcellus, Haynesville, and Barnett shales. Derek Rice holds a BS in geological sciences from Tufts University and a MS in geology from the University of Houston. He is the son of Daniel J. Rice III and the brother of Daniel J. Rice IV and Toby Rice.
Grayson T. Lisenby has served as our Vice President and Chief Financial Officer since October 2013. Mr. Lisenby joined Rice Energy in February 2013, initially serving as our Vice President of Finance. Prior to joining Rice Energy, Mr. Lisenby was an investment professional at Natural Gas Partners from July 2011 to January 2013 and concentrated on transaction analysis and execution as well as the monitoring of active portfolio companies. Mr. Lisenby was involved in NGP’s original $100 million investment into Rice Energy and spent a significant amount of his time monitoring and advising the company during his tenure at Natural Gas Partners. Prior to his employment at NGP, he served an investment banker for Barclays Capital Inc.’s energy group in Houston from August 2009 to July 2011. Mr. Lisenby holds a BBA in Finance from the University of Texas, where he was a member of the Business Honors Program.
James W. Rogers has served as our Vice President, Chief Accounting & Administrative Officer and Treasurer, since October 2013. Mr. Rogers joined Rice Energy in April 2011 as Controller and subsequently served as our Vice President and Chief Accounting Officer from January 2012 through October 2012 and our Chief Financial Officer from November 2012 through September 2013. Prior to joining Rice Energy, Mr. Rogers served as a Financial Specialist with EQT Corporation, working in the Corporate Accounting Group, from May 2010 to March 2011. Prior to EQT, Mr. Rogers served as an assurance manager for Ernst & Young in their Pittsburgh office from September 2007 to April 2010. He began his career in 2002 as an auditor with PricewaterhouseCoopers LLP, in its Pittsburgh office. Mr. Rogers is a certified public accountant in the state of Pennsylvania and holds a BSBA in accounting from the University of Pittsburgh. He is also a member of the AICPA.
William E. Jordan has served as our Vice President, General Counsel and Corporate Secretary since January 2014. From September 2005 through December 2013, Mr. Jordan practiced corporate law at Vinson & Elkins L.L.P., representing public and private companies in capital markets offerings and mergers and acquisitions, primarily in the oil and natural gas industry. He is a graduate of Davidson College with a BA in Mathematics and a graduate of the Duke University School of Law with a Doctor of Jurisprudence degree.
Robert F. Vagt has served as the chairman of our board of directors since January 2014. Mr. Vagt has served as a member of the board of directors of Kinder Morgan, Inc. since May 2012, where he serves as a member of the audit committee. Mr. Vagt served as a member of the board of directors of El Paso Corporation from May 2005 until June 2012, where he was a member of the compensation and health, safety and environmental committees. From January 2008 until January 2014, Mr. Vagt was also the President of The Heinz Endowments. Prior to his tenure at The Heinz Endowments, Mr. Vagt served as President of Davidson College from July 1997 to August 2007. Mr. Vagt served as President and Chief Operating Officer of Seagull Energy Corporation from 1996 to 1997. From 1992 to 1996, he served as President, Chairman and Chief Executive Officer of Global Natural Resources. Mr. Vagt served as President and Chief Operating Officer of Adobe Resources Corporation from 1989 to 1992. Prior to 1989, he served in various positions with Adobe Resources Corporation and its predecessor entities.
The board believes that Mr. Vagt’s professional background in both the public and private sectors make him an important advisor and member of our board of directors. Mr. Vagt brings to the board operations and management expertise in both the public and private sectors. In addition, Mr. Vagt provides the board with a welcomed diversity of perspective gained from service as President of The Heinz Endowments, as well as from service as the president of an independent liberal arts college.
Daniel J. Rice III has served as a member of our board of directors since October 2013. He has also served as Managing General Partner of Rice Partners. Since January 2013, Mr. Rice has served as Lead Portfolio Manager for GRT Capital’s energy division. From 2005 to December 2012, Mr. Rice served as a Managing Director and Portfolio Manager for BlackRock, Inc. and was a member of BlackRock, Inc.’s Global Resources team, responsible for Small Cap and All Cap Energy funds. Prior to joining BlackRock, Inc. in 2005, he was a Senior Vice President and Portfolio Manager at State Street Research & Management, responsible for the Small Cap Energy and All Cap Energy Global Resources Funds. Prior to joining State Street Research in 1984, he was a Vice President and Portfolio Manager with Fred Alger Management. Earlier in his career, Mr. Rice was a Vice President and Analyst with EF Hutton and an Analyst with Loomis Sayles and Co. He began his career in 1975 as an auditor with Price Waterhouse & Co. He earned a BS degree from Bates College in 1973 and an MBA degree from New York University in 1975. Mr. Rice has more than 30 years of experience in the oil and gas industry. He is the father of Toby Rice, Daniel J. Rice IV and Derek Rice.
The board believes that Mr. Rice’s considerable financial and energy investing experience brings important and valuable skills to the board of directors.
Scott A. Gieselman has served as a member of our board of directors since April 2013. Mr. Gieselman has been a managing director of Natural Gas Partners since April 2007. From 1988 to April 2007, Mr. Gieselman worked in various positions in the investment banking energy group of Goldman, Sachs & Co., where he became a partner in 2002. Mr. Gieselman received a BS from the Boston College Carroll School of Management in 1985 and a MBA from the Boston College Carroll Graduate School of Management in 1988.
The board believes that Mr. Gieselman’s considerable financial and energy investment banking experience, as well as his experience on the boards of numerous private energy companies, bring important and valuable skills to the board of directors.
Chris G. Carter has served as a member of our board of directors since October 2013. Mr. Carter is a managing director of Natural Gas Partners. Prior to joining Natural Gas Partners in 2004, Mr. Carter was an analyst with Deutsche Bank’s Energy Investment Banking group in Houston, where he focused on financing and merger and acquisition transactions in the oil and gas and oilfield services industries. Mr. Carter received a B.B.A. and an M.P.A. in Accounting, summa cum laude, in 2002 from the University of Texas, where he was a member of the Business Honors Program. He received an M.B.A. in 2008 from Stanford University, where he graduated as an Arjay Miller Scholar.
The board believes that Mr. Carter’s considerable financial and energy investing experience, as well as his experience on the boards of numerous private energy companies, bring important and valuable skills to the board of directors.
James W. Christmas has served as a member of our board of directors since January 2014. Mr. Christmas has served as a member of the board of directors of Halcón Resources Corporation since February 2012. Mr. Christmas began serving as a director of Petrohawk Energy Corporation in July 2006, effective upon the merger of KCS Energy, Inc. (“KCS”) into Petrohawk. He continued to serve as a director, and as Vice Chairman of the Board of Directors, for Petrohawk until BHP Billiton acquired all of Petrohawk in August 2011. He also served on the audit committee and the Nominating and Corporate Governance Committee. Currently, Mr. Christmas serves as a member of the Board of Directors of Petrohawk, a wholly-owned subsidiary of BHP Billiton, and as chair of the Financial Reporting Committee of such board. He also serves on the Advisory Board of the Tobin School of Business of St. John’s University and as a member of the board of directors of a private oil and gas company. He served as President and Chief Executive Officer of KCS from 1988 until April 2003 and Chairman of the Board and Chief Executive Officer of KCS until its merger into Petrohawk. Mr. Christmas was a Certified Public Accountant in New York and was with Arthur Andersen & Co. from 1970 until 1978 before leaving to join National Utilities & Industries (“NUI”), a diversified energy company, as Vice President and Controller. He remained with NUI until 1988, when NUI spun out its unregulated activities that ultimately became part of KCS. As an auditor and audit manager, controller and in his role as CEO of KCS, Mr. Christmas was directly or indirectly responsible for financial reporting and compliance with SEC regulations, and as such has extensive experience in reviewing and evaluating financial reports, as well as in evaluating executive and board performance and in recruiting directors.
The board believes that Mr. Christmas’s prior experience as an executive and director and his past audit, accounting and financial reporting experience provide significant contributions to our board of directors.
Kevin S. Crutchfield has served as a member of our board of directors since January 2014. Mr. Crutchfield has served as the chairman of the board of directors (since May 2012) and chief executive officer (since July 2009) of Alpha Natural Resources, Inc., an international supplier of metallurgical and thermal coal. He has been with Alpha since its formation in 2003, serving as executive vice-president from November 2004 to January 2007, president from January 2007 to July 2009, and as a director since November 2007. Mr. Crutchfield is a 25-year coal industry veteran with technical, operating and executive management experience. He is currently the vice chairman of the National Mining Association and the American Coalition for Clean Coal
Electricity. Prior to joining Alpha, Mr. Crutchfield was vice president of El Paso Corporation and president of Coastal Coal Company, an affiliate of El Paso. He previously served as president of AMVEST Corporation and held executive positions at AEI Resources, Inc., including president and chief executive officer. Earlier in his career, he held senior management positions at Pittston Coal Company and Cyprus Australia Coal Company, including a period in Australia as chairman of Cyprus Australia Coal Company. Mr. Crutchfield also serves on the board of directors of Coeur d’Alene Mines Corporation and previously served on the board of directors at King Pharmaceuticals, Inc. from February 2010 until the first quarter of 2011, when he resigned in connection with the acquisition of King Pharmaceuticals by Pfizer.
The board believes that Mr. Crutchfield’s prior experience in corporate leadership, financial and operational management, government and regulatory oversight, health and safety management, and industry expertise through his various executive roles in global natural resource businesses, in addition to experience in public company board leadership provide significant contributions to our board of directors.
Board of Directors
Our board of directors currently consists of eight members: Robert F. Vagt (Chairman), Daniel J. Rice IV, Toby Z. Rice, Daniel J. Rice III, Scott A. Gieselman, Chris G. Carter, James W. Christmas and Kevin S. Crutchfield.
In connection with the closing of our IPO, we entered into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc. Please see “Item 13. Certain Relationships and Related Transactions and Director Independence.” Pursuant to the stockholders’ agreement, we and our principal stockholders agreed to appoint individuals designated by the principal stockholders to our board of directors and nominate such persons for election at each annual meeting of our stockholders.
We expect to add another independent director to our board of directors and audit committee within one year of the initial listing of our common stock on the NYSE. Our board has reviewed the independence of our current directors using the independence standards of the NYSE and, based on this review, determined that Messrs. Gieselman, Carter, Vagt and Christmas are independent within the meaning of the NYSE listing standards currently in effect. As a result, we expect that our board of directors will consist of nine members within one year of the initial listing of our common stock on the NYSE, five of whom will be independent.
In evaluating director candidates, we assess whether a candidate possesses the integrity, judgment, knowledge, experience, skills and expertise that are likely to enhance the board’s ability to manage and direct our affairs and business, including, when applicable, to enhance the ability of the committees of the board to fulfill their duties. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal or until their successors have been duly elected and qualified.
Our directors are divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors serve until our annual meetings of stockholders in 2015, 2016 and 2017, respectively. Messrs. Daniel J. Rice IV, Carter and Christmas are assigned to Class I, Messrs. Toby Z. Rice, Crutchfield and Vagt are assigned to Class II and Messrs. Daniel J. Rice III and Gieselman are assigned to Class III. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.
Status as a Controlled Company
Because Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc. collectively beneficially own a majority of our outstanding common stock following the completion of our IPO and are deemed a group as a result of the stockholders’ agreement entered into in connection with the closing of our IPO, we are a controlled company under NYSE corporate governance standards. A controlled company need not comply with NYSE corporate governance rules that require its board of directors to have a majority of independent directors and independent compensation and nominating and governance committees.
While these exemptions will apply to us as long as we remain a controlled company, we expect that our board of directors will nonetheless consist of a majority of independent directors within the meaning of the NYSE listing standards currently in effect within one year of the initial listing of our common stock on the NYSE.
Committees of the Board of Directors
We have an audit committee, a compensation committee, a nominating and corporate governance committee and a health, safety & environmental committee of our board of directors, and we may form such other committees as the board of directors
shall determine from time to time in the future. Each of the standing committees of the board of directors has the composition and responsibilities described below.
Audit Committee
Rules implemented by the NYSE and SEC require us to have an audit committee comprised of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act, subject to transitional relief during the one-year period following the initial listing of our common stock on the NYSE. Our audit committee consists of Messrs. Christmas (Chair) and Vagt, each of whom is independent under the rules of the SEC. Subsequent to the transitional period, we will comply with the requirement to have three independent directors on our audit committee. As required by the rules of the SEC and listing standards of the NYSE, the audit committee consists solely of independent directors. Our board has determined that Mr. Christmas satisfies the definition of “audit committee financial expert.”
This committee oversees, reviews, acts on and reports on various auditing and accounting matters to our board of directors, including: the selection of our independent accountants, the scope of our annual audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to legal and regulatory requirements. We have an audit committee charter defining the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. A copy of our audit committee charter is posted on our website at http://investors.riceenergy.com/committee-charters.
Compensation Committee
Our compensation committee establishes salaries, incentives and other forms of compensation for officers and other employees. Our compensation committee also administers our incentive compensation and benefit plans. Our compensation committee charter defines the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. Our compensation committee consists of Messrs. Vagt (Chair), Christmas and Carter, each of whom is independent under the rules of the NYSE. A copy of our compensation committee charter is posted on our website at http://investors.riceenergy.com/committee-charters.
Nominating and Corporate Governance Committee
Because we are a controlled company within the meaning of the NYSE corporate governance standards, we are not required to have a nominating and governance committee composed entirely of independent directors. However, we have a nominating and corporate governance committee, which identifies, evaluates and recommends qualified nominees to serve on our board of directors, develops and oversees our internal corporate governance processes and maintains a management succession plan. Our nominating and corporate governance committee charter defines the committee’s primary duties in a manner consistent with the rules of the SEC and applicable stock exchange or market standards. Our nominating and governance committee consists of Messrs. Gieselman (Chair), Daniel J. Rice III and Daniel J. Rice IV. A copy of our nominating and corporate governance committee charter is posted on our website at http://investors.riceenergy.com/committee-charters.
Health, Safety and Environmental Committee
We have a health, safety and environmental committee. This committee assists the board in fulfilling its risk oversight responsibilities relating to health, safety and environmental-related matters, including environmental regulations, health and safety initiatives and accountabilities, and crisis response. Our health, safety and environmental committee consists of Messrs. Toby Z. Rice (Chair), Vagt and Crutchfield.
Section 16(a) Beneficial Ownership Reporting Compliance
Our executive officers and directors and persons who own more than 10% of a class of our equity securities registered pursuant to Section 12 of the Exchange Act are required to file certain reports with the SEC, disclosing the amount and nature of their beneficial ownership in common stock, as well as changes in that ownership. We had no equity securities registered pursuant to Section 12 of the Exchange Act during the year ended December 31, 2013 and, as a result, no such reports were required to be filed.
Code of Business Conduct and Ethics
Our board of directors has adopted a code of business conduct and ethics applicable to our employees, directors and officers, in accordance with applicable U.S. federal securities laws and the corporate governance rules of the NYSE. Any waiver of this code may be made only by our board of directors and will be promptly disclosed as required by applicable U.S. federal securities laws and the corporate governance rules of the NYSE.
Corporate Governance Guidelines
Our board of directors believes that sound governance practices and policies provide an important framework to assist it in fulfilling its duty to stockholders. Our Corporate Governance Guidelines cover the following principal subjects:
•Role and functions of the board of directors
•Qualifications and independence of directors
•Size of the board of directors and director selection process
•Committee functions and independence of committee members
•Meetings of non-employee directors
•Self-evaluation
•Ethics and conflicts of interest (a copy of the current “Code of Business Conduct and Ethics” is posted on the our website at http://investors.riceenergy.com/codeofconduct)
•Compensation of the board of directors
•Succession planning
•Access to senior management and to independent advisors
•New director orientation
•Continuing education
The “Corporate Governance Guidelines” are posted on the our website at http://investors.riceenergy.com/corporate-governance. The Corporate Governance Guidelines will be reviewed periodically and as necessary by our nominating and governance committee, and any proposed additions to or amendments of the Corporate Governance Guidelines will be presented to the board of directors for its approval.
The NYSE has adopted rules that require listed companies to adopt governance guidelines covering certain matters. We believe that the Corporate Governance Guidelines comply with the NYSE rules.
Board Leadership
Mr. Vagt has served as the chairman of our board of directors since the completion of our IPO in January 2014. Although our Chief Executive Officer currently does not serve as chairman of our board, we currently have no policy prohibiting our current or any future chief executive officer from serving as chairman. Our board of directors, in recognizing the importance of the board having the ability to operate independently, determined that separating the roles of chairman and chief executive officer is advantageous for us and our stockholders. Our board of directors has also determined that having the chief executive officer serve as a director enhances understanding and communication between management and the board of directors, allows for better comprehension and evaluation of our operations, and ultimately improves the ability of the board of directors to perform its oversight role.
Additionally, the board of directors regularly meets in executive session without the presence of the chief executive officer or other members of management. The chairman presides at these meetings and provides the board of directors’s guidance and feedback to our management team. Further, the board of directors has complete access to our management team.
Communications with the Board of Directors
Stockholders or other interested parties can contact the board of directors, any committee of the board of directors, the chairman of the board of directors or any other director in particular by writing to them at the following address: Rice Energy Inc. 171 Hillpointe Drive, Suite 301, Canonsburg, Pennsylvania 15317. Comments or complaints relating to our accounting, internal accounting controls or auditing matters will also be referred to members of the audit committee. All such communications will be forwarded to the appropriate member(s) of the board of directors.
Director Independence
Our standards for determining director independence require the assessment of directors’ independence each year. A director cannot be considered independent unless the board affirmatively determines that he or she does not have any relationship with us or our management that may interfere with the exercise of his or her independent judgment, including any of the relationships that would disqualify the director from being independent under the rules of the NYSE.
The board of directors has assessed the independence of each non-employee director and under our guidelines and the independence standards of the NYSE. The board of directors affirmatively determined that Messrs. Carter, Christmas, Gieselman and Vagt are independent.
In connection with its assessment of the independence of each non-employee director, the board also determined that Messrs. Christmas and Vagt meet the additional independence standards of the NYSE and SEC applicable to members of the audit committee. Those standards require that the director not be an affiliate of us and that the director not receive from us, directly or indirectly, any consulting, advisory or other compensatory fees except for fees for services as a director. We expect to add another independent director to our board of directors and audit committee within one year after the completion of our IPO.
Financial Literacy of Audit Committee and Designation of Financial Experts
The board of directors evaluated the members of the audit committee, Messrs. Vagt and Christmas, in January 2014 for financial literacy and the attributes of a financial expert. The board of directors determined that each of the audit committee members is financially literate and that the chairman of the audit committee, Mr. Christmas, is an audit committee financial expert as defined by the SEC.
Oversight of Risk Management
Except as discussed below, the board of directors as a whole oversees our assessment of major risks and the measures taken to manage such risks. For example:
•the board of directors has the authority and expects to oversee management of our commodity price risk through regular review with executive management of our derivatives strategy, and the oversight of our policy that limits our authority to enter into derivative commodity price instruments to a specified level of production, above which management must seek board approval;
•the board of directors has the authority and expects to establish specific dollar limits on the commitment authority of members of senior management and requires board approval of expenditures exceeding that authority and of other material contracts and transactions; and
•the board of directors has the authority and expects to review management’s capital spending plans, approve our capital budget and requires that management present for board review significant departures from those plans.
Our audit committee is responsible for overseeing our assessment and management of financial reporting and internal control risks, as well as other financial risks, such as the credit risks associated with counterparty exposure. Management and our independent registered public accountants report regularly to the audit committee on those subjects. The board of directors does not consider its role in oversight of our risk management function to be relevant to its choice of leadership structure.
Attendance at Annual Meetings
The board of directors encourages all directors to attend the annual meetings of stockholders, if practicable.
Item 11.
Item 11. Executive Compensation
Named Executive Officers
For fiscal year 2013, our Named Executive Officers were as follows. Please see “Item 10. Directors, Executive Officers and Corporate Governance” for a description of our current executive officers, including historical roles held by our 2013 Named Executive Officers.
(1)
Mr. Daniel J. Rice IV’s role with our company changed during 2013. In 2013, he served as our Vice President and Chief Operating Officer from January through September and thereafter as our Chief Executive Officer.
(2)
Mr. Toby Z. Rice’s role with our company changed during 2013. In 2013, he served as our Chief Executive Officer from January through September and thereafter as our President and Chief Operating Officer.
(3)
Mr. Lisenby’s role with our company changed during 2013. Mr. Lisenby joined our company in February 2013, initially serving as our Vice President of Finance through September. Thereafter, Mr. Lisenby served as our Vice President and Chief Financial Officer.
(4)
Mr. Rogers’s role with our company changed during 2013. In 2013, he served as our Vice President and Chief Financial Officer from January through September and thereafter as our Vice President and Chief Accounting & Administrative Officer, Treasurer.
Summary Compensation Table
The following table summarizes, with respect to our Named Executive Officers, information relating to the compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2013.
(1)
The amounts in this column represent the aggregate amount of annual discretionary cash bonuses paid to our Named Executive Officers for fiscal year 2013 performance.
(2)
As discussed more fully below in the “Long Term Incentive Compensation” section of the narrative accompanying this table, each of the Named Executive Officers holds outstanding Incentive Units that are not classified as equity for accounting purposes. However, because satisfaction of the performance conditions related to these awards is not probable, no amounts have been treated as earned in 2013 for purposes of this table.
(3)
Amounts reported in the “All Other Compensation” column reflect company matching contributions to the Named Executive Officers’ 401(k) plan retirement accounts.
Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year
In connection with our IPO, we engaged Alvarez & Marsal (“A&M”), a global professional services firm, as our compensation consultant to provide recommendations regarding our compensation arrangements. The following discussion describes the elements of our 2013 executive compensation program.
Base Salary
Each Named Executive Officer’s base salary is a fixed component of compensation for each year for performing specific job duties and functions. Prior to our IPO, an informal compensation committee comprised of Messers. D. Rice IV, T. Rice, and D. Rice III (collectively, the “Committee”) established the annual base salary rate for each of the Named Executive Officers at a level necessary to retain the individual’s services and reviewed base salaries on an annual basis at the end of each year, with adjustments implemented at the beginning of the next year. The Committee historically made adjustments to the base salary rates of the Named Executive Officers upon consideration of any factors that it deemed relevant, including but not limited to: (a) any increase or decrease in the executive’s responsibilities, (b) the executive’s job performance, and (c) the level of compensation paid to executives of other companies with which we compete for executive talent, as estimated based on publicly available information and the experience of members of the Committee. Notwithstanding the foregoing, under the Limited Liability Company Agreement of Rice Appalachia, dated January 25, 2012, as amended from time to time (the “REA LLC Agreement”), annual compensation and benefits (except for Incentive Units granted by Rice Appalachia’s Board of Managers under the REA LLC Agreement) for our Named Executive Officers historically required the approval of Natural Gas Partners, except to extent that such annual salaries did not exceed $150,000 for each of Messrs. T. Rice and D. Rice IV. Such requirement was eliminated with the amendment of the REA LLC Agreement in connection with our IPO.
In connection with our IPO, the Committee analyzed the appropriateness of the base salary for each of our Named Executive Officers in light of the base salaries of other executives in the peer group that we identified with the assistance of A&M, both on a stand-alone basis and as a component of total compensation. This review resulted in the establishment of the following annual base salaries for each of our Named Executive Officers, which became effective upon the IPO for the remainder of the 2014 year: $400,000 for each of Messrs. D. Rice IV and T. Rice and $300,000 for each of Messrs. Lisenby and Rogers.
Annual Cash Bonus
Prior to the IPO, annual cash bonus awards for Messers. T. Rice and D. Rice IV were discretionary awards awarded by the Committee at the end of each fiscal year. The determination of the amount of these discretionary cash bonus awards, if any, was made based on an overall assessment of our company’s performance in light of overall market conditions, along with these Named Executive Officers’ individual performance, for the fiscal year, and was not based on any one or more specific performance objective or criteria.
The amount of annual bonus for Messrs. Lisenby and Rogers for 2013 was determined under a separate award program that applies to certain of our key employees. This program is administered under the Rice Energy Management Bonus Plan (the “Bonus Plan”), as established in January 2010 and amended from time to time. Under the Bonus Plan, for 2013, a targeted bonus amount expressed as a percentage of annual base salary was established for each of Messrs. Lisenby and Rogers. The determination of the amount of annual bonus payable for 2013 for each of Messrs. Lisenby and Rogers was made in the discretion of the Committee. In making this determination, the Committee historically considered each participating employee’s targeted bonus award amount (expressed as a percentage of the employee’s base salary) and the employee’s individual performance and contributions during the year, including his completion of job-specific duties, but the Committee retained full discretion to pay less than or more than the individual’s targeted bonus award amount. Due to our strong performance in 2013 and the contributions of Messrs. Lisenby and Rogers thereto, these two executives were awarded the full amount of their targeted bonus of $145,000, and $126,750, respectively. We intend to continue to provide annual incentive cash bonuses to reward achievement of financial or operational goals so that total compensation reflects actual company and individual performance. We expect that our new compensation committee may establish performance goals to be used in determining the cash bonuses that may become payable for future performance periods. In addition, our new compensation committee is currently analyzing data of a peer group of companies, and we expect that they will establish target cash bonuses for 2014 based on their analysis.
Long-Term Incentive Compensation
Incentive Units
Prior to our IPO, the only long-term incentives offered to our Named Executive Officers were through grants of Incentive Units, which were profits interests representing an interest in the future profits (once a certain level of proceeds has been generated) of our predecessor parent entity Rice Appalachia and granted pursuant to the REA LLC Agreement. These profits interests (the “REA Incentive Units”) represented interests in Rice Appalachia that had no value for tax purposes on the date of grant and were designed to gain value only after the underlying assets had realized a certain level of growth and return to those individuals who hold certain classes of Rice Appalachia’s equity. The REA Incentive Units were intended to provide the holders with the ability to benefit from the growth in our operations and business. In connection with our IPO and the related corporate reorganization, the Named Executive Officers (and other REA Incentive Unit holders) contributed their REA Incentive Units
(except for those related to the incentive burden attributable to Mr. Daniel J. Rice III) to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities.
In 2013, each of the Named Executive Officers held outstanding REA Incentive Units granted pursuant to the REA LLC Agreement. The profits interest awards were divided into seven tiered classes as follows: Legacy Tier I Units, Legacy Tier II Units, Legacy Tier III Units, New Tier I Units, New Tier II Units, New Tier III Units, and New Tier IV Units. A potential payout for each tier would have occurred only after a specified level of cumulative cash distributions had been received by Natural Gas Partners. Legacy Tier I Units were designed to vest in three equal annual installments, with such annual vesting occurring on the anniversaries of the grant date and with pro-rata monthly vesting between these annual anniversary dates. Legacy Tier II Units and Legacy Tier III Units would each have vested only upon the payment threshold established for that tier (described below). New Tier I Units and New Tier II Units were designed to vest in five equal annual installments on each anniversary of the grant date of such awards and with pro-rata monthly vesting between these annual anniversary dates. New Tier III Units and New Tier IV Units would each have vested only upon the payment threshold established for that tier (described below). In addition to the time-based vesting that applied to the Legacy Tier I Units, New Tier I Units, and New Tier II Units, such awards were also subject to accelerated vesting in full upon the occurrence of a “Fundamental Change” (as defined in the REA LLC Agreement and described below).
The difference between a vested and unvested unit was that once a unit vested, the executive would retain all vested profits interest awards as non-voting interests, unless such executive’s employment was terminated for “Cause” (as defined below) or voluntarily resigns. All profits interest awards that had not vested according to their original vesting schedule at the time an executive’s employment was terminated for any reason would be forfeited without payment. If we terminated an executive for Cause, or the executive voluntarily terminated his or her employment, all vested profits interest awards would also be forfeited at the time of the termination. If distributions were made with respect to a tier of these profits interest awards, both vested and unvested units (to the extent not previously forfeited) would receive the distributions and the holder of such units would be entitled to keep any such distributions regardless of whether the units were subsequently forfeited.
Under the REA LLC Agreement, the Legacy Tier I, Legacy Tier II and Legacy Tier III Units were entitled to 10%, 10% and 10%, respectively, of distributions to members only after Natural Gas Partners had received cumulative distributions in respect of their membership interests equal to two times, three times and four times, respectively, of the cumulative capital contributions made prior to April 18, 2013. The New Tier I Units and New Tier II Units were entitled to 20% and 5%, respectively, of distributions to members only after Natural Gas Partners had received cumulative distributions in respect of their membership interests equal to their cumulative capital contributions made on or after April 18, 2013, multiplied by (1.08)n and (1.20)n, respectively, where “n” was equal to a weighted average capital contribution factor determined as of the dates of the distributions. The New Tier III Units and New Tier IV Units were entitled to 5% and 5%, respectively, of distributions to members only after Natural Gas Partners had received cumulative distributions in respect of their membership interests equal to two times and 2.5 times, respectively, their cumulative capital contributions made on or after April 18, 2013.
As used in the paragraphs above, a “capital contribution” to Rice Appalachia generally means, for any member thereof, the dollar amount of any cash and the fair market value of any property contributed to Rice Appalachia.
A termination for “Cause” would have generally occurred upon the individual’s (i) conviction of, or plea of nolo contendere to, any felony or crime causing substantial harm to us or our affiliates or involving acts of theft, fraud, embezzlement, moral turpitude or similar conduct; (ii) repeated intoxication by alcohol or drugs during the performance of the individual’s duties in a manner that materially and adversely affects the individual’s performance of such duties; (iii) malfeasance in the conduct of the individual’s duties; (iv) violation of any voting or transfer restriction agreement or a confidentiality and noncompete agreement that the individual has executed with us; and (v) failure to perform the duties of the individual’s service relationship with us or our affiliates, or failure to follow or comply with the reasonable and lawful written directives of our board of managers or the board of an affiliate employing or engaging the service of such individual, as applicable.
A “Fundamental Change” was generally deemed to have occurred when Rice Appalachia entered into any merger or consolidation with another entity, the outstanding interests in the company were sold or exchanged, or Rice Appalachia sold, leased, exchanged, or licensed all or substantially all of its assets, in each case other than with or to a related entity and only if Rice Appalachia’s existing board members did not continue to constitute at least a majority of the members of the board of the surviving or acquiring entity immediately following the transaction. A Fundamental Change was also deemed to have occurred if any single person or entity (or groups of such related persons or entities) purchased or acquired the right to vote or dispose of the company’s securities in an amount representing 50% or more of the total voting power of all the then outstanding voting securities of Rice Appalachia unless such transaction has been approved by Rice Appalachia’s board of managers (provided that no capital contribution by certain Natural Gas Partners entities shall constitute a Fundamental Change). Our IPO, and the related corporate reorganization did not constitute a Fundamental Change.
Prior to our IPO, no tier of the profits interest awards had received a payout. Since no amount of the outstanding REA Incentive Units held by our Named Executive Officers had been earned (as the performance conditions related to payout were not probable of occurring) as of December 31, 2013 and the awards were not accounted for under Financial Accounting Standards Board Accounting Standards Topic 718 (“FASB ASC Topic 718”), the value of these profits interests had not been included in our Summary Compensation Table. In connection with our corporate reorganization, approximately 160,831 shares of our common stock were issued to certain of the incentive holders in exchange for the portion of their REA Incentive Units related to the incentive burden attributable to Mr. Daniel J. Rice III. In connection with our IPO, in the first quarter of 2014, we recognized a non-cash compensation expense of $3.4 million. Also, in connection with our IPO, in the first quarter of 2014, certain incentive units granted by NGP Holdings to certain members of management triggered the pre-determined payout criteria, resulting in a cash payment of $4.4 million. This resulted in additional non-cash compensation expense.
In connection with our IPO and the related corporate reorganization, the Named Executive Officers (and other REA Incentive Unit holders) contributed their REA Incentive Units (except for those related to the incentive burden attributable to Mr. Daniel J. Rice III) to Rice Holdings and NGP Holdings in return for substantially similar incentive units in such entities. As a result, the burden of the incentive units previously attributable to Rice Partners and Natural Gas Partners was replicated in the limited liability company agreements of Rice Holdings and NGP Holdings, respectively. The limited liability company agreement of NGP Holdings entitles holders of incentive units to a portion of distributions made by NGP Holdings. Generally, it is anticipated that such distributions will occur in connection with sales of our common stock by NGP Holdings. Accordingly, if the requisite cumulative cash distribution thresholds to Natural Gas Partners have been met, incentive unitholders are entitled to cash distributions on any applicable class of incentive units at such time. Following the end of the 2013 fiscal year, on January 30, 2014, a distribution threshold was satisfied and NGP Holdings made certain cash distributions to incentive unit holders; Messrs. Daniel Rice, Toby Rice, Lisenby and Rogers received aggregate payments in the amount of $376,376; $486,647; $557,076 and $114,626, respectively, related to their incentive units. Similarly, the limited liability company agreement of Rice Holdings entitles holders of incentive units to a portion of distributions made by Rice Holdings. However, incentive unitholders in Rice Holdings are not entitled to receive distributions of distributable funds until the earlier of January 2, 2016, or 30 days following the date on which NGP Holdings has sold in excess of 50% of its Rice Energy Inc. common stock (including pursuant to our IPO). On such date and each of the three anniversaries thereafter, Rice Holdings will distribute one-quarter of its distributable funds, including shares of our common stock, to its members. Accordingly, if requisite cumulative distribution thresholds to Rice Partners have been met, incentive unitholders are entitled to distributions of either cash or our common stock on any applicable class of incentive units at such times. As of the date of this filing, no distributions have been made to the incentive unit holders from Rice Holdings. Because we are not a party to the limited liability company agreements of Rice Holdings or NGP Holdings, we cannot be certain that the terms of the profits interest units will not change in the future.
Long-Term Incentive Plan
In order to incentivize management members, our board of directors adopted an omnibus long-term incentive plan for employees, consultants, and directors. Our Named Executive Officers are eligible to participate in the long-term incentive plan (“LTIP”) which provides for the grant of bonus stock, restricted stock, restricted stock units, options, stock appreciation rights, dividend equivalent rights, performance awards, annual incentive awards and other stock-based awards intended to align the interests of key employees (including the Named Executive Officers) with those of our stockholders. We did not grant any equity awards under the LTIP to our Named Executive Officers during the 2013 year, and as of the date of this filing we have not granted LTIP awards to our Named Executive Officers in the 2014 year.
Other Compensation Elements
We also offer participation in broad-based retirement and health and welfare plans to all of our employees. We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code whereby employees, including our Named Executive Officers, are allowed to contribute portions of their compensation (which includes all compensation reported on Form W-2 for the year) to a tax-qualified retirement account. See “-Additional Narrative Disclosure Regarding Retirement Benefits and Other Potential Payments Upon Termination or a Change in Control-Retirement Benefits” for more information.
Outstanding Equity Awards at 2013 Fiscal Year-End
None of our Named Executive Officers held any outstanding equity awards that were accounted for under FASB ASC Topic 718 as of December 31, 2013.
Additional Narrative Disclosure Regarding Retirement Benefits and Other Potential Payments Upon Termination or a Change in Control
Retirement Benefits
We have not maintained, and do not currently maintain, a defined benefit pension plan or a nonqualified deferred compensation plan providing for retirement benefits. We currently maintain a retirement plan intended to provide benefits under section 401(k) of the Code, under which employees, including our Named Executive Officers, are allowed to contribute portions of their compensation to a tax-qualified retirement account. Under our 401(k) plan, we provide matching contributions equal to 100% of the first 6% of employees’ eligible compensation contributed to the plan.
Employment, Severance or Change in Control Agreements
As described in more detail under “-Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year-Long-Term Incentive Compensation” above, the REA Incentive Units held by our Named Executive Officers were to be either forfeited or remain outstanding following the officer’s termination of employment, with no acceleration of vesting or payment being made under the awards upon such termination of employment.
Prior to our IPO, we historically had not maintained any employment, severance or change in control agreements with any of our Named Executive Officers. In addition, none of the Named Executive Officers were entitled to any payments or other benefits in connection with a termination of their employment or a change in control during the 2013 year, except that in certain instances, (1) our employees may be entitled to receive, upon a sale of the company or substantially all of our assets, amounts of already earned annual bonus awards under our Bonus Plan to the extent such amounts have not yet been paid at the time such transaction occurs, and (2) a change in control (a “Fundamental Change,” as such term is defined in the REA LLC Agreement and summarized under “-Narrative Description to the Summary Compensation Table for the 2013 Fiscal Year-Long Term Incentive Compensation-Incentive Units” above may result in a cash distribution being made to holders of vested REA Incentive Units, in accordance with the distribution priority specified in the REA LLC Agreement (unvested REA Incentive Units do not become vested upon a change in control).
In connection with our IPO, our Named Executive Officers entered into employment agreements with us on January 29, 2014. Under these new employment agreements, each of our Named Executive Officers is entitled to certain severance benefits upon a qualifying termination of employment and the employment agreements preclude the executives from soliciting employees or competing with us for a period of one year following termination of employment.
The description of the employment agreements set forth below is a summary of the material features of the agreements regarding potential payments upon termination or a change in control. This summary, however, does not purport to be a complete description of all the provisions of the agreements with the executives. This summary is qualified in its entirety by reference to the employment agreements, which are filed as exhibits to this Annual Report.
Under the terms of the new employment agreements, each Named Executive Officer is entitled to receive the following amounts (the “Accrued Rights”) upon a termination by the company for “cause” (as such term is defined below), upon a termination of employment by reason of death, disability, or expiration of the term of the employment agreement, or upon the executive’s termination without “good reason” (as such term is defined below): (a) payment of all accrued and unpaid base salary to the date of termination, (b) reimbursement of all incurred but unreimbursed business expenses to which the executive would have been entitled to reimbursement, and (c) benefits to which the executive is entitled under the terms of any applicable benefit plan or program. If the termination is due to death or disability, such Named Executive Officer is also entitled to accelerated vesting of any outstanding LTIP awards.
Under the terms of the employment agreements, each Named Executive Officer is also entitled to receive the following amounts upon a termination by the executive for “good reason” (as such term is defined below) or by the company without “cause” (as such term is defined below): (a) the Accrued Rights; (b) any earned but unpaid annual bonus for the prior year; (c) a prorated annual bonus for the year of termination; (d) a severance payment equal to one times (two times in the event of a qualifying termination within the 12-month period following a “change in control” as such term is defined below) the sum of the executive’s base salary on the date of termination and the average annual bonus for the three prior calendar years; and (e) accelerated vesting of any outstanding LTIP awards held by the executive as of the date of termination. The Named Executive Officers are also entitled to continued coverage under our group health plan for any COBRA period (up to 18 months) elected for the executive and the executive’s spouse and eligible dependents, at no greater premium cost than that which applies to our active senior executive employees.
The following terms are defined under the employment agreements for the Named Executive Officers, as described below:
•“Cause” means a determination by the board of directors (or its delegates) that the executive (a) has engaged in gross negligence, gross incompetence, or misconduct in the performance of the executive’s duties to us, (b) has failed without proper legal reason to perform the executive’s duties and responsibilities to us, (c) has breached any material provision of the employment agreement or any written agreement or corporate policy or code of conduct established by us, (d) has engaged in conduct that is, or could reasonably expected to be, materially injurious to us, (e) has committed an act of theft, fraud, embezzlement, misappropriation, or breach of a fiduciary duty to us, or (f) has been convicted of, pleaded no contest to, or received adjudicated probation or deferred adjudication in connection with a crime involving fraud, dishonesty, or moral turpitude or any felony (or a crime of similar import in a foreign jurisdiction).
•“Good Reason” means (a) a material diminution in the executive’s base salary (as defined in the employment agreements), other than as a part of one or more decreases that (i) shall not exceed, in the aggregate, more than 10% of the base salary as in effect on the date immediately prior to such decrease, and (ii) are applied similarly to all of our similarly situated executives; (b) a material diminution in the executive’s authority, duties, or responsibilities; or (c) the involuntary relocation of the geographic location of the executive’s principal place of employment by more than 75 miles from the location of the executive’s principal place of employment as of the effective date of the employment agreement.
•“Change in Control” generally means (a) a merger, consolidation, or sale of all or substantially all of our assets if (i) our shareholders do not continue to own at least 50% of the voting power of the resulting entity in substantially the same proportions that they owned our equity securities prior to the transaction or event or (ii) the members of our board immediately prior to the transaction or event do not constitute at least a majority of the board of directors of the resulting entity immediately after the transaction or event; (b) the dissolution or liquidation of the company; (c) when any person, entity, or group acquires or gains ownership or control of more than 50% of the combined voting power of the outstanding securities of the company, or (d) as a result of or in connection with a contested election of directors, the persons who were members of our board immediately before such election cease to constitute a majority of the board.
Compensation of Directors
We did not award any compensation to our non-employee directors during 2013. Going forward, our board of directors believes that attracting and retaining qualified non-employee directors will be critical to the future value growth and governance of our company. Our board of directors also believes that the compensation package for our non-employee directors should require a portion of the total compensation package to be equity-based to align the interest of these directors with our stockholders.
Except with respect to designees of Rice Holdings and NGP Holdings, we have implemented the following non-employee director compensation program: (a) an annual cash retainer valued at approximately $250,000 for the chairman of our board, $60,000 for our committee chairmen and $50,000 for all other non-employee directors, and (b) an annual LTIP award valued at approximately $250,000 for the chairman of our board and $110,000 for all other non-employee directors. We do not pay any additional fees for attendance at board or committee meetings, but we do reimburse each director for travel and miscellaneous expenses to attend meetings and activities of our board or its committees. In addition, two of our non-employee directors, Robert F. Vagt and James W. Christmas, received initial grants of restricted stock units upon the closing of our IPO in the amount of 11,905 and 5,238, respectively, that are subject to a one-year cliff vesting schedule. Directors who are also our employees and directors who are designees of Rice Holdings and NGP Holdings do not receive any additional compensation for their service on our board of directors.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Beneficial Ownership
The following table sets forth certain information regarding the beneficial ownership of our common stock as of March 21, 2014 by (i) each person who is known by us to own beneficially more than five percent of our outstanding shares of common stock, (ii) each of our named executive officers, (iii) each member of our board of directors and (iv) all of our directors and executive officers as a group. Unless otherwise noted, the mailing address of each person or entity named below is c/o Rice Energy Inc., 171 Hillpointe Drive, Suite 301, Canonsburg, Pennsylvania 15317.
*
Less than one percent.
(1)
Based upon an aggregate of 127,958,611 shares outstanding as of March 21, 2014.
(2)
Rice Partners is the sole member of Rice Holdings. Rice Energy Management LLC is the general partner of Rice Partners. Rice Energy Management LLC is controlled by a board of managers, consisting solely of Daniel J. Rice III. By virtue of his relationship with Rice Partners, Daniel J. Rice III is deemed to have an indirect beneficial interest in the shares of common stock held by Rice Partners. Daniel J. Rice III directly owns 2,356,844 shares of our common stock. Rice Partners has indicated that it may pledge all or a portion of its shares of our common stock as collateral under a credit agreement it may enter into in the future.
(3)
Rice Holdings is controlled by a board of managers consisting of Daniel J. Rice IV, Toby Z. Rice and Daniel J. Rice III.
(4)
NGP Holdings is indirectly owned by Natural Gas Partners IX, L.P. and an affiliate thereof (“NGP IX”) and NGP Natural Resources X, L.P. and an affiliate thereof (“NGP X”). NGP IX and NGP X may be deemed to share voting and dispositive power over the reported securities, and therefore, may also be deemed to be the beneficial owner of these securities. NGP IX and NGP X disclaim beneficial ownership of the reported securities in excess of such entity’s respective pecuniary interest in the securities. G.F.W. Energy IX, L.P. and GFW IX, L.L.C. may be deemed to share voting and dispositive power over the reported securities, and therefore, may also be deemed to be the beneficial owner of these shares by virtue of GFW IX, L.L.C. being the sole general partner of G.F.W. Energy IX, L.P. (which is the sole general partner of NGP IX). G.F.W. Energy X, L.P. and GFW X, L.L.C. may be deemed to share voting and dispositive power over the reported securities, and therefore, may also be deemed to be the beneficial owner of these shares by virtue of GFW X, L.L.C. being the sole general partner of G.F.W. Energy X, L.P. (which is the sole general partner of NGP X). David R. Albin and Kenneth A. Hersh, each an Authorized Member of GFW IX, L.L.C. and GFW X, L.L.C., may also be deemed to share the power to vote, or to direct the vote, and to dispose, or to direct the disposition, of the securities owned by NGP Holdings. Mr. Hersh and Mr. Albin disclaim beneficial ownership of the securities, except to the extent of their respective pecuniary interest therein. Neither Mr. Hersh nor Mr. Albin owns directly any such securities. GFW IX, L.L.C. and GFW X, L.L.C. have delegated full power and authority to manage NGP IX and NGP X, respectively to NGP Energy Capital Management, L.L.C. and accordingly, NGP Energy Capital Management, L.L.C. may be deemed to share voting and dispositive power over these securities and therefore may also be deemed to be the beneficial owner of these securities.
(5)
Based on the most recent Schedule 13D and Form 4 filed with the SEC by such holder. Alpha Holdings is a wholly owned indirect subsidiary of Alpha Natural Resources, Inc., and as such, Alpha Natural Resources, Inc. will be deemed to be the beneficial owner of these securities. The mailing address for each of Alpha Holdings and Alpha Natural Resources Inc. is One Alpha Place, P.O. Box 16429, Bristol, Virginia.
(6)
Includes 11,905 restricted stock units that vest in a single installment on January 29, 2015.
(7)
Includes 5,238 restricted stock units that vest in a single installment on January 29, 2015.
(8)
Includes 23,810 restricted stock units granted to Mr. Jordan that vest in a single installment on January 29, 2017.
Equity Compensation Plans
At December 31, 2013, we had no securities authorized for issuance under equity compensation plans.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence Procedures for Review, Approval and Ratification of Related Person Transactions
Prior to the closing of our IPO, we did not maintain a policy for approval of Related Party Transactions. A “Related Party Transaction” is a transaction, arrangement or relationship in which we or any of our subsidiaries was, is or will be a participant, the amount of which involved exceeds $120,000, and in which any Related Person had, has or will have a direct or indirect material interest. A “Related Person” means:
•
any person who is, or at any time during the applicable period was, one of our executive officers or one of our directors;
•
any person who is known by us to be the beneficial owner of more than 5% of our common stock;
•
any immediate family member of any of the foregoing persons, which means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law of a director, executive officer or a beneficial owner of more than 5% of our common stock, and any person (other than a tenant or employee) sharing the household of such director, executive officer or beneficial owner of more than 5% of our common stock; and
•
any firm, corporation or other entity in which any of the foregoing persons is a partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest.
Our board of directors has determined that the audit committee will periodically review all related person transactions that the rules of the SEC require be disclosed in our annual report or proxy statement, as applicable, and make a determination regarding the initial authorization or ratification of any such transaction.
The audit committee is charged with reviewing the material facts of all related person transactions and either approving or disapproving of our participation in such transactions under our Related Persons Transaction Policy adopted by the board on January 23, 2014, which pre-approves certain related person transactions, including:
•any employment of an executive officer if his or her compensation is required to be reported in the our annual report or proxy statement under Item 402;
•director compensation which is required to be reported in the our annual report or proxy statement under Item 402;
•any transaction with another company at which a Related Person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s shares is pre-approved or ratified (as applicable) if the aggregate amount involved for any particular service does not exceed the greater of $1.0 million or 5% of that company’s total annual revenues; and
•charitable contribution, grant or endowment by us to a charitable organization, foundation or university at which a Related Person’s only relationship is as an employee (other than an executive officer) or a director is pre-approved or ratified (as applicable) if the aggregate amount involved does not exceed the lesser of $200,000 or 5% of the charitable organization’s total annual receipts.
In determining whether to approve or disapprove entry into a Related Party Transaction, the audit committee shall take into account, among other factors, the following: (1) whether the Related Party Transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances and (2) the extent of the Related Person’s interest in the transaction. Further, the policy requires that all Related Party Transactions required to be disclosed in our filings with the SEC be so disclosed in accordance with applicable laws, rules and regulations.
There were no Related Party Transactions since January 23, 2014 which were required to be reported in “Transactions with Related Persons,” where the procedures described above did not require review, approval or ratification or where these procedures were not followed. In addition, since January 1, 2013, there has not been, any transaction or series of similar transactions to which we were or are a party in which the amount involved exceeded or exceeds $120,000 and in which any of our directors, executive officers, holders of more than 5% of any class of our voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest, other than compensation arrangements with directors and executive officers, which are described in “Item 10. Executive Compensation,” and the transactions described or referred to below.
Historical Transactions with Affiliates
Since its inception, Rice Drilling B has issued additional membership interests as consideration for capital contributions received from Rice Appalachia. Capital contributions for the year ended December 31, 2013 and the year ended December 31, 2012 were $198.2 million and $113.0 million, respectively. Rice Appalachia made no capital contributions to Rice Drilling B for the year ended December 31, 2011.
The capital contributions made by Rice Appalachia were the result of capital contributions made to Rice Appalachia by the following individuals and entities:
•Daniel J. Rice III: $0.2 million and $14.0 million for the years ended December 31, 2013 and 2012, respectively;
•Rice Partners: $49.9 million for the year ended December 31, 2012; and
•Natural Gas Partners $198.0 million and $99.0 million for the years ended December 31, 2013 and 2012, respectively.
In addition, Rice Drilling B has paid legal fees of Natural Gas Partners totaling approximately $30 thousand and $0.4 million for the years ended December 31, 2013 and 2012, respectively, in connection with these transactions.
NGP received a put right with respect to their equity investment in Rice Drilling B (indirectly, through its investment in Rice Appalachia) which is contingently exercisable upon the occurrence of certain events. The earliest date that this put right could be exercised is January 25, 2017. The fair value of this put right is de minimis given the accretion in fair value of Rice Appalachia and this put right is no longer be applicable following the completion of our IPO.
In prior periods, we reimbursed Rice Partners for expenses incurred on our behalf. General and administrative expenses incurred by Rice Partners and reimbursed by us were $9.3 million, $4.8 million and $3.1 million for the years ended December 31, 2013 , 2012 and 2011, respectively. As of December 31, 2013 and 2012, $6.1 million and $2.5 million, respectively, of general and administrative expenses was due to Rice Partners and is recorded as due to affiliate on the consolidated balance sheet. This agreement was terminated prior to the closing of our IPO.
We are reimbursed for costs incurred on behalf of our Marcellus joint venture. General and administrative expenses incurred by us and reimbursed by our Marcellus joint venture were $1.6 million, $1.3 million and $0.0 million for the years ended December 31, 2013, 2012 and 2011, respectively. As of December 31, 2012, we recorded a receivable from our Marcellus joint venture for $4.6 million representing leaseholds that were approved to be contributed to the joint venture. There was no such receivable as of December 31, 2013.
In January 2010, Rice Energy Limited Partnership assigned its 100% membership interest in Rice Drilling C LLC (“Rice C”) to Rice Drilling B. At the date of the transfer of membership interest, Rice C’s assets consisted solely of approximately $0.9 million.
In November 2009, we entered into restricted unit agreements with an employee and certain consultants. Under separate and individual restricted unit agreements, the eligible employee and consultants were granted units which vest over a specified period of time. Each unit entitles the holder to an equity ownership in us. The restricted units are accounted for as liability awards, which require re-measurement each reporting period, as a result of the existence of a call option that permits us to repurchase the awards at a fixed amount that could be above or below fair market value of the units. Management established an estimated fair value for issued units based upon an income approach prior to December 31, 2013. At December 31, 2013, in connection with the IPO, a market approach was used. During the years ended December 31, 2013, 2012 and 2011, $32.9 million, $0.0 million and $0.2 million, respectively, of restricted unit expense was recognized for these awards. During 2012, Rice Appalachia, as the designee of Rice Drilling B, exercised the option to repurchase certain restricted units from a consultant. In connection with our IPO, the balance of the restricted units outstanding was exchanged for 1,728,852 shares of our common stock.
On October 28, 2009, we entered into a subordinated working capital promissory note payable to Daniel J. Rice III in the amount of $4.0 million. The note accrued interest at a rate of 1.20% and interest only is due at maturity on February 1, 2018. This note was converted to equity in January 2012.
On February 1, 2009, the terms of a $10.0 million subordinated related party promissory note payable to Daniel J. Rice III were modified. For accounting purposes, the cash flows of the promissory note were considered substantially different resulting in extinguishment accounting. There were no financing fees recorded for the promissory note. The fair value of the modified promissory note was compared to the carrying value of the original promissory note with the difference resulting in a capital contribution from the related party of $3.6 million. The fair value was estimated based upon an estimate of market rates at the
inception of the promissory note. The discount was amortized over the life of the instruments using an effective interest rate of 4.6%. This note was converted to equity in January 2012.
Marcellus JV Buy-In Transaction Agreement
On January 29, 2014, in connection with the closing of our IPO and pursuant to the Transaction Agreement, we completed our acquisition of Alpha Holdings’ 50% interest in our Marcellus joint venture to us in exchange for total consideration of $300.0 million, consisting of $100.0 million of cash and our issuance to Alpha Holdings of 9,523,810 shares of our common stock.
Registration Rights Agreement
In connection with the closing of our IPO, we entered into a registration rights agreement with Rice Holdings, Rice Partners, Daniel J. Rice III, NGP Holdings and Alpha Holdings, referred to herein as the Initial Holders. Pursuant to the registration rights agreement, we have agreed to register the sale of shares of our common stock under certain circumstances.
Demand Rights. Subject to the limitations set forth below, any Initial Holder (or their permitted transferees) has the right to require us by written notice to prepare and file a registration statement registering the offer and sale of a number of their shares of common stock. Generally, we are required to provide notice of the request within five business days following the receipt of such demand request to all additional holders of our common stock, who may, in certain circumstances, participate in the registration. In no event shall more than one demand registration occur during any six-month period or within 180 days (with respect to our IPO) or 90 days (with respect to any public offering other than our IPO) after the effective date of a final Annual Report we file. Further, we are not obligated to effect:
•(i) through December 31, 2016, more than a total of three demand registrations or (ii) on or after January 1, 2017, more than a total of one demand registration per calendar year at the request of Rice Holdings;
•more than one demand registration for Daniel J. Rice III;
•(i) through December 31, 2016, more than a total of three demand registrations or (ii) on or after January 1, 2017, more than a total of one demand registration per calendar year at the request of NGP Holdings; or
•more than one demand registration for Alpha Holdings.
We are also not obligated to effect any demand registration in which the anticipated aggregate offering price included in such offering is less than $30 million. Once we are eligible to effect a registration on Form S-3, any such demand registration may be for a shelf registration statement. Any demand for an underwritten offering pursuant to an effective shelf registration statement shall constitute a demand request subject to the limitations set forth above. We will be required to maintain the effectiveness of any such registration statement until the earlier of 180 days (or two years if a “shelf registration” is requested) after the effective date and the consummation of the distribution by the participating holders.
Piggy-back Rights. If, at any time, we propose to register an offering of common stock (subject to certain exceptions) for our own account, then we must give at least five business days’ notice to all holders of registrable securities to allow them to include a specified number of their shares in that registration statement.
Conditions and Limitations; Expenses. These registration rights are subject to certain conditions and limitations, including the right of the underwriters to limit the number of shares to be included in a registration and our right to delay or withdraw a registration statement under certain circumstances. We will generally pay all registration expenses in connection with our obligations under the registration rights agreement, regardless of whether a registration statement is filed or becomes effective.
Stockholders’ Agreement
In connection with the closing of our IPO, we entered into a stockholders’ agreement with Rice Holdings, Rice Partners, NGP Holdings and Alpha Natural Resources, Inc. Pursuant to the stockholders’ agreement, we and our principal stockholders agreed to appoint individuals designated by the principal stockholders to our board of directors and nominate such persons for election at each annual meeting of our stockholders, subject to the following:
•
Rice Holdings has the right to nominate three members of our board of directors, provided that such number of nominees shall be reduced to two and zero if Rice Holdings and its affiliates, which includes Rice Partners and Dan Rice III, collectively own less than 15% and 5%, respectively, of the outstanding shares of our common stock;
•
NGP Holdings has the right to nominate two members of our board of directors, provided that such number of nominees shall be reduced to one and zero if NGP Holdings and its affiliates collectively own less than 15% and 5%, respectively, of the outstanding shares of our common stock;
•
Alpha Natural Resources, Inc. has the right to nominate one member of our board of directors, provided that such number of nominees shall be reduced to zero if Alpha Natural Resources, Inc. and its affiliates collectively own less than 5% of the outstanding shares of our common stock.
The nominee designated by Alpha Natural Resources, Inc. must be either (i) the Chief Executive Officer of Alpha Natural Resources, Inc. at the time of designation or (ii) a member of senior management (with a title of Senior Vice President or greater) of Alpha Natural Resources, Inc. that is reasonably satisfactory to us.
The stockholders’ agreement also requires the stockholders party thereto to take all necessary actions, including voting their shares of common stock, for the election of the nominees designated by such principal stockholders.
Item 14.
Item 14. Principal Accounting Fees and Services
The table below sets forth the aggregate fees billed related to audit and tax fees on a pro forma basis (in thousands):
(1) Audit fees represent fees for professional services provided in connection with (a) audit of our financial statements, (b) review of our quarterly consolidated financial statements and (c) review of our filings with the SEC, including review of registration statements, comfort letters and consents.
(2)
None.
(3)
Tax fees primarily represent advice related to structuring of corporate reorganization.
For the years ended December 31, 2013 and 2012, we did not have an audit committee or pre-approval policy. The charter of the audit committee and its pre-approval policy, each adopted in connection with or subsequent to our IPO, require that the audit committee review and pre-approve the plan and scope of Ernst & Young LLP’s audit, audit-related, tax and other services.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
a. The following documents are filed as a part of this Annual Report on Form 10-K or incorporated herein by reference:
(1) Financial Statements:
See Item 8. Financial Statements and Supplementary Data.
(2) Financial Statement Schedules:
None.
(3) Exhibits:
The exhibits listed on the accompanying index to exhibits (pages 163 through 165) are filed as part of this Annual Report on Form 10-K.
Index to Exhibits
Exhibits are incorporated by reference or are filed with this report as indicated below (numbered in accordance with Item 601 of Regulation S-K).
(a)
Filed herewith.
(b)
Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this Annual Report on Form 10-K and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act, as amended, or otherwise subject to the liability of Section 18 of the Securities Exchange Act, as amended, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Exchange Act of 1933, as amended, except to the extent that the registrant specifically incorporates it by reference.
*
The schedules to this agreement have been omitted from this filing pursuant to Item 601(b)(2) of Regulation S-K. The Company will furnish copies of such schedules to the Securities and Exchange Commission upon request.
†
Management contract or compensatory plan or agreement
Signatures
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:
“Bcf.” One billion cubic feet of natural gas.
“Btu.” One British thermal unit, the quantity of heat required to raise the temperature of a one-pound mass of water by one degree of Fahrenheit.
“Basin.” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Completion.” The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.
“DD&A.” Depreciation, depletion, amortization and accretion.
“Delineation.” The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.
“Developed acreage.” The number of acres that are allocated or assignable to productive wells or wells capable of production.
“Development well.” A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“Dry gas.” A natural gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
“Dry hole.” A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
“EUR.” Estimated ultimate recovery.
“Exploratory well.” A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.
“Field.” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“Formation.” A layer of rock which has distinct characteristics that differs from nearby rock.
“Gross acres” or “gross wells.” The total acres or wells, as the case may be, in which a working interest is owned.
“Gross (net) identified drilling locations.” Gross (net) identified drilling locations are those drilling locations identified by management based on the following criteria:
•
Drillable Locations - These are mapped locations that our Vice President of Exploration & Geology has deemed to have a high likelihood as being drilled or are currently in development but have not yet commenced production. With respect to our Pennsylvania acreage, we had 224 gross (200 net) pro forma drillable Marcellus locations and 134 gross (117 net) pro forma drillable Upper Devonian locations as of December 31, 2013. With respect to our Ohio acreage, as of December 31, 2013, we had 637 gross (192 net) drillable Utica locations, all of which are located within the contract areas covered by our Development Agreement and AMI Agreement with Gulfport.
•
Estimated Locations - These remaining estimated locations are calculated by taking our total acreage, less acreage that is producing or included in drillable locations, and dividing such amount by our expected well spacing to arrive at our unrisked estimated locations which is then multiplied by a risking factor. We assume these Marcellus locations have 6,000 foot laterals and 600 foot spacing between Marcellus wells which yields approximately 80 acre spacing. We assume these Upper Devonian locations have 6,000 foot laterals and 1,000 foot spacing between Upper Devonian wells which yields approximately 140 acre spacing. We assume these Utica locations have 8,000 foot laterals and 600 foot spacing between Utica wells which yields approximately 110 acre spacing. With respect to our Pennsylvania acreage, we multiply our unrisked estimated Marcellus and Upper Devonian locations by a risking factor of 50% to arrive at total risked estimated
locations. As a result, we had 125 gross (125 net) pro forma estimated risked Marcellus locations and 77 gross (77 net) pro forma estimated risked Upper Devonian locations as of December 31, 2013. With respect to our Ohio acreage, we multiply our unrisked estimated locations by a risking factor of approximately 37% to arrive at total risked estimated locations. We then apply our assumed working interest for such location, calculated by applying the impact of assumed unitization on the underlying working interest as well as, in the case of locations within the AMI with Gulfport, the applicable participating interest. As a result, as of December 31, 2013, we had 116 gross (41 net) estimated risked Utica locations. Estimated locations include ununitized locations that have been risked (50% in the Marcellus, 37% in the Utica) to take into account the risk of forming drilling units.
•
Net Unrisked Locations - Consist of Drillable Locations and Estimated Locations without applying our risking factor. We assume 450 net unrisked Marcellus locations (200 pro forma net drillable Marcellus locations and 250 pro forma net estimated unrisked Marcellus locations). We assume 304 net unrisked Utica locations (192 pro forma net drillable Utica locations and 112 net estimated unrisked Utica locations).
•
Net Risked Locations - Consist of Drillable Locations and Estimated Locations. We assume 325 net risked Marcellus locations (200 pro forma net drillable Marcellus locations and 125 pro forma net estimated risked Marcellus locations). We assume 233 net risked Utica locations (192 pro forma net drillable Utica locations and 41 net estimated risked Utica locations).
“Horizontal drilling.” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
“Identified drilling locations.” Total gross (net) resource play locations that we may be able to drill on our existing acreage. Actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.
“Mcf.” One thousand cubic feet of natural gas.
“MMcf.” One million cubic feet of natural gas.
“MMBtu.” One million Btu.
“NGLs.” Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.
“NYMEX.” The New York Mercantile Exchange.
“Net acres.” The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.
“Productive well.” A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“Prospect.” A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
“Proved developed reserves.” Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved reserves.” The estimated quantities of oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
“Proved undeveloped reserves (“PUD”).” Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
“PV-10.” When used with respect to natural gas and oil reserves, PV-10 means 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.
“Recompletion.” The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
“Reservoir.” A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Spacing.” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
“Standardized measure.” Discounted future net cash flows estimated by applying year-end prices to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the natural gas and oil properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“Total depth.” The planned end of a well, measured by the length of pipe required to reach the bottom.
“Undeveloped acreage.” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
“Unit.” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“Wellbore.” The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.
“Working interest.” The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.