Item 1. Business
Overview
Laredo is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. The oil and liquids-rich Permian Basin is characterized by multiple target horizons, extensive production histories, long-lived reserves, high drilling success rates and high initial production rates. We operate and analyze our results of operations through our two principal business segments:
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Exploration and production of oil and natural gas properties - conducted principally by Laredo Petroleum, Inc. through the exploration and development of our acreage in the Permian Basin. As of December 31, 2015, we had assembled 135,408 net acres in the Permian Basin and had total proved reserves, presented on a three-stream basis, of 125,698 MBOE.
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Midstream and marketing - conducted principally by our wholly-owned subsidiary, LMS. LMS buys, sells, gathers and transports oil, natural gas and water primarily for the account of Laredo. In addition, LMS owns a 49% interest in Medallion Gathering & Processing, LLC ("Medallion"), which, upon completion of current projects, will own and operate 500 miles of pipeline in the Permian Basin. This system gathered, transported and delivered 69,000 Bbls per day in the fourth quarter of 2015.
Financial information and other disclosures relating to our business segments are provided in the notes to our consolidated financial statements included elsewhere in this Annual Report (see Note 17 to our consolidated financial statements included elsewhere in this Annual Report).
2015 segment operation highlights
Exploration and production
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Produced a Company record 16.3 MMBOE in 2015, an increase of 18% from 2014
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Received $255.3 million of cash settlements on commodity derivatives that matured during 2015
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Reduced general and administrative ("G&A") expenses to $5.53 per BOE in 2015, a decrease of 28% from 2014
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Reduced capital expenditures in exploration and development activities and other fixed assets to $530.2 million in 2015, a decrease of 60% from 2014, to more appropriately align capital with expected cash flows
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Utilized the Company's proprietary Earth Model to design the drilling plan for the majority of horizontal wells drilled in 2015
Midstream and marketing
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Gathered 4.6 million barrels of crude oil, an increase of 190% from 2014
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Gathered 28.5 Bcf of natural gas, an increase of 55% from 2014
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Supplied 12.9 Bcf of natural gas lift supply, an increase of 480% from 2014
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Commenced commercial operations of the Medallion crude oil gathering system, in which LMS owns a 49% interest, growing Medallion transported volumes of oil to 69,000 Bbls per day in the fourth quarter and 15.2 million barrels of crude oil for the year
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Commenced operations of our water treatment facility in the second half of the year that provided 1.2 million barrels of recycled water for completion operations in the second half of the 2015 and 800,000 barrels during the last seven weeks of the year
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Invested capital of $159.6 million in pipelines and related infrastructure held by LMS, including investments in the Medallion pipeline system
Our core assets
Exploration and production
The Permian Basin is comprised of several distinct geological provinces, including the Midland Basin to the east, the Delaware Basin to the west and the Central Platform in the middle. Our primary development and production fairway is located on the east side of the Midland Basin, 35 miles east of Midland, Texas. Our acreage is largely contiguous in the neighboring counties of Howard, Glasscock, Reagan, Sterling and Irion, Texas. We refer to this acreage block in this Annual Report as our "Permian-Garden City" area. As of December 31, 2015, we held 135,408 net acres in the Permian Basin, with 131,763 of the net acres held in 250 sections in the Permian-Garden City area, with an average working interest of 95% in all Laredo-operated producing wells.
We believe our acreage in the Permian-Garden City area is a resource play for multiple producing formations that partially make up the vertical Wolfberry interval. To date, we have focused the majority of our development activities in four targets for horizontal drilling (Upper, Middle and Lower Wolfcamp and Cline formations), although we have established the existence of additional producing zones, including the Spraberry and Canyon. From our inception in 2006 through December 31, 2015, we have drilled and completed (i.e., the particular well is flowing) 230 horizontal wells in these initial four identified target zones and 967 vertical wells in the Wolfberry interval. We have completed 97 horizontal Upper Wolfcamp wells, 48 horizontal Middle Wolfcamp wells, 30 horizontal Lower Wolfcamp wells and 55 horizontal Cline wells.
Beginning in mid-2012, we started focusing our horizontal activity on drilling longer laterals (typically 7,000 to 7,500 feet). Where our contiguous acreage position allows, we have now evolved to drilling 10,000-foot laterals.
Due to the sharp decline in oil, NGL and natural gas prices that began in the second half of 2014 and continued through 2015 and the beginning of 2016, we reduced our 2016 planned capital program. In connection with the reduced capital program, we have approved a capital budget of $345 million for 2016. Of this budget, $330 million is allocated to our exploration and production segment and $15 million is allocated to our midstream and marketing segment. Substantially all of the planned capital budget is anticipated to be invested in the Permian-Garden City area for both of our segments. Our near-term goal is to concentrate our drilling activities along our previously established production corridors that have the infrastructure in place to allow us the flexibility to most efficiently and economically drill wells at an attractive rate of return, even during the current period of depressed commodity prices. We will also continue to seek cost saving measures to more efficiently deploy our capital, including decreasing our unit lease operating and G&A expenses. We anticipate that in conjunction with the continued downward trend in commodity prices, capital and service costs may continue to decline as well, although there can be no assurance of any such decline.
In connection with our reduced capital budget, we are decreasing the number of horizontal drilling rigs and eliminating vertical drilling rigs working our properties in the Permian-Garden City area as we do not believe that any vertical drilling is currently necessary under our leases. On December 31, 2015, we had a total of three operated drilling rigs drilling horizontal wells. Our current drilling schedule anticipates that we will average 2.5 horizontal rigs and no vertical rigs in 2016.
The timing of drilling our potential locations is influenced by several factors, including commodity prices, capital requirements and availability, the Texas Railroad Commission ("RRC") well-spacing requirements and the continuation of the positive results from our ongoing development drilling program.
We expect our Permian-Garden City acreage to continue to be the primary driver of our reserves, production and cash flow for the foreseeable future.
Since our inception, we have established and realized our reserves, production and cash flow primarily through our drilling program coupled with select strategic acquisitions, including our July 2011 acquisition of Broad Oak. Our net proved reserves were estimated at 125,698 MBOE on a three-stream basis as of December 31, 2015, of which 80% are classified as proved developed reserves and 42% are attributed to oil reserves. For all periods prior to January 1, 2015, our reserves and production were reported in two streams: crude oil and liquids-rich natural gas. This means the economic value of the natural gas liquids in our natural gas was included in the wellhead natural gas price and total volumes on a BOE-basis are lower. Beginning on January 1, 2015, we started reporting our production volumes on a three-stream basis, which separately reports NGL from crude oil and natural gas. In this Annual Report, the information presented with respect to our estimated proved reserves has been prepared by Ryder Scott Company, L.P. ("Ryder Scott"), our independent reserve engineers, in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC") applicable to the periods presented.
The following table summarizes our total estimated net proved reserves presented on a three-stream basis, net acreage and producing wells as of December 31, 2015, and average daily production presented on a three-stream basis for the year ended December 31, 2015. Based on estimates in the report prepared by Ryder Scott, we operated wells that represent 99% of the economic value of our proved developed oil, NGL and natural gas reserves as of December 31, 2015.
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See "-Our operations-Estimated proved reserves" for discussion of the prices utilized to estimate our reserves.
Our net average daily production for the year ended December 31, 2015 was 44,782 BOE/D, 47% of which was oil, 26% of which was NGLs and 27% of which was natural gas.
As discussed previously in this Annual Report, during 2015 commodity prices for crude oil, NGL and natural gas experienced sharp declines, and this downward trend has accelerated further into the first quarter of 2016, with crude oil prices reaching a twelve-year low in February 2016. We have significantly reduced our capital budget for 2016. In addition, we have purposely significantly reduced the portion of our reserves that have historically been categorized as "proved undeveloped" or "PUD." We have adjusted our long-range five-year SEC PUD bookings methodology because given the current economic price environment, coupled with (i) our efforts to develop our acreage in the most efficient manner possible and determine which potential locations will be most profitable and (ii) the uncertain effect that such environment will have on the industry’s access to the capital markets, we believe that we can optimize the value for our shareholders by maintaining greater flexibility in choosing the specific drilling locations that may yield the greatest rates of return.
As our activities to date have indicated, the majority of our acreage represents a resource play. In the near-term, our goal is to drill those locations that we anticipate have the potential to provide the greatest economic return and enhance shareholder value, and we have determined that the most efficient way to accomplish this is to maintain the flexibility to choose those locations based upon our continuing insight as we drill and collect data across our acreage, regardless of SEC reserve-booking status. Reducing our future PUD commitments provides us the most flexibility to maximize our rate of return at prevailing conditions and minimize the requirement to drill wells previously assigned under very different circumstances as specific PUD locations. Accordingly, we have reduced our booked PUD locations to those we have reasonable certainty to believe that we will develop in at least a two-year time horizon while maintaining the flexibility to add new PUD locations and convert other locations to proved developed reserves as our plans deem appropriate and opportunistic.
We have built an extensive proprietary technical database that includes 398 in-house, core-calibrated petrophysical logs, 992 square miles of 3D seismic, 44 microseismic surveys, more than 1,090 open and cased-hole logging suites, including 133 dipole sonic logs, 2,866 feet of proprietary whole cores in 13 wells, 859 sidewall cores, 39 single-zone tests and 42 production logs. Our strategic interest in assembling a rich database is directed at efficiently gaining a knowledge base on our resource play in the Permian-Garden City area and maximizing value during the field development phase.
A key component of our reservoir characterization process is internally referred to as the "Earth Model," which represents a proprietary integrated workflow combining geoscience and engineering data with multivariate statistics. The workflow employed in the Earth Model process differs from the more conventional earth science/engineering approach in that the Earth Model involves parallel workflows, multivariate statistics and significant input from multiple disciplines. The goal of the Earth Model is to develop a predictive three-dimensional model that can forecast production rates through associating empirical subsurface data with proved methods.
We have been developing the Earth Model process over a period of four years, covering an area where calibrated pre-stack inversion attributes have been extensively developed and tested to determine fundamental controls on reservoir performance. The four major components of the Earth Model are (i) geophysical data (i.e., 3D seismic and micro-seismic surveys), (ii) logs (i.e., conventional open-hole, dipole sonic, and in-house core calibrated petrophysical logs), (iii) cores (both whole and sidewall) and (iv) production history, production logs and single-zone tests. By integrating data that represent mechanical properties, natural fractures, reservoir properties and lithology within a multivariate statistical model, we were generally able to develop a relationship to production with correlation coefficients for our 2016 targeted zones.
We consider the Earth Model a potentially significant tool in planning development wells in complex geology by optimizing landing points, lateral lengths and geo-steering targets while integrating horizontal and vertical spacing considerations for well laterals.
We estimate that more than 90% of our horizontal wells to be drilled in 2016 will utilize at least some aspects of the Earth Model, demonstrating evolution from a calibrated backward-looking model into a primary tool for development and delineation well planning. If our preliminary applications of the Earth Model are replicated in forward-looking well planning, we anticipate that the Earth Model may positively impact our ability to increase initial production rates and estimated ultimate recoveries.
Midstream and marketing
We are actively involved in seeking midstream solutions for our oil, NGL and natural gas production. Capitalizing on our large acreage blocks, we have built crude oil, natural gas and/or water systems in four production corridors on our Permian-Garden City acreage. These production corridors provide high-pressure centralized natural gas lift systems and crude oil and natural gas gathering, with certain corridors also capable of water delivery, takeaway and recycling (including 77 miles of fresh, produced and recycled water lines). In 2015, we commenced operations at our water treatment facility, which is capable of recycling more than 28,000 Bbls of water per day and has a storage capacity of 1.4 million Bbls. We believe the fact that these production corridors and associated facilities and infrastructure are already in place will enable us to more economically undertake our anticipated 2016 drilling program.
Additionally, we have built and maintain more than 40 miles of crude oil gathering pipelines to connect Laredo-operated wells in our Permian-Garden City asset, providing a safer and more economic transportation alternative than trucking. We have also installed and maintain 175 miles of natural gas gathering pipelines across our Permian-Garden City acreage, providing us with takeaway optionality that enables us to maintain lower operating pressures and more consistent well performance.
LMS is a 49% owner in the Medallion crude oil gathering system which commenced operations in March of 2015. Upon completion of current projects, the system will have 500 miles of laid pipeline in the following counties in Texas: Mitchell, Howard, Martin, Midland, Glasscock, Reagan, Upton, Crane and Crockett. During the portion of the year in 2015 that it was operational, the system transported 15.2 million Bbls of crude oil. See Notes 15 and 16.a to our consolidated financial statements included elsewhere in this Annual Report for a discussion of Medallion.
Our midstream and marketing activities continue to focus on achieving increased efficiencies and cost reductions for (i) the transportation and marketing of our oil and natural gas through the utilization of our oil and natural gas gathering systems to provide access to multiple markets and reduce the potential for production shut-ins caused by downstream capacity issues and (ii) the handling of fresh, recycled and produced water.
We market the majority of production from properties we operate for both our account and the account of the other working interest owners in our operated properties. We sell substantially all of our production under contracts ranging from one month to several years, all at market prices. We normally sell production to a relatively limited number of customers, as is customary in the exploration, development and production business; however, we believe that our customer diversification affords us optionality in our sales destination. We have committed a portion of our Permian crude oil production under firm
transportation agreements, including with Medallion, which agreements will enhance our ability to move our crude oil out of the Permian Basin and give us access to potentially more favorable Gulf Coast pricing.
As of December 31, 2015, we were committed to deliver for sale or transportation the following fixed quantities of production under certain contractual arrangements that specify the delivery of a fixed and determinable quantity.
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BOE equivalents are calculated using a conversion rate of six Mcf per one Bbl.
We have firm field transportation agreements that enable us or the purchasers of our oil production to move oil from our production area to the major market hubs of Midland, Texas and Colorado City, Texas. We also have a firm transportation agreement to move oil from Colorado City, Texas to the U.S. Gulf Coast. We expect to fulfill these firm transportation commitments primarily by utilizing the volumes under our firm sales commitments.
Our production has been equivalent or greater than our delivery commitments during the three most recent years, and we expect such production will continue to exceed our future commitments. However, in certain instances, we have used spot market purchases to meet commitments in certain locations or due to favorable pricing. We anticipate continuing this practice in the future. Also, if our production is not sufficient to satisfy our delivery commitments, we can and may use spot market purchases to fulfill the commitments.
In the current market environment, we believe that we could sell our production to numerous companies so that the loss of any one of our major purchasers would not have a material adverse effect on our financial condition and results of operations solely by reason of such loss. For information regarding each of our customers that accounted for 10% or more of our oil, NGL and natural gas revenues during the last three calendar years, see Note 11 to our consolidated financial statements included elsewhere in this Annual Report. See "Item 1A.
Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risks described elsewhere in this Annual Report, were actually to occur, our business, financial condition or results of operations could be materially adversely affected and the trading price of our shares could decline resulting in the loss of part or all of your investment. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider immaterial may also adversely affect us.
Risks related to our business
Oil, NGL and natural gas prices are volatile. The continuing and extended decline in oil, NGL and natural gas prices has adversely affected, and may continue to adversely affect, our business, financial condition and results of operations and may in the future affect our ability to meet our capital expenditure obligations and financial commitments as well as negatively impact our stock price further.
The prices we receive for our oil, NGL and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil, NGL and natural gas are commodities, and therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the market for oil, NGL and natural gas has been volatile, and this volatility exhibited a negative trend in the second half of 2014 which has continued through 2015 and into the first quarter of 2016. 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 and financial conditions impacting the global supply and demand for oil, NGL and natural gas;
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the level of global oil, NGL and natural gas exploration and production;
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the level of global oil, NGL and natural gas supplies, in particular due to supply growth from the United States;
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foreign and domestic supply capabilities for oil, NGL and natural gas;
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the price and quantity of U.S. imports and exports of oil, natural gas, including liquefied natural gas, and NGL;
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political conditions in or affecting other oil, NGL and natural gas-producing countries, including the current conflicts in the Middle East, and conditions in South America, Africa, Ukraine and Russia;
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actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil, NGL and natural gas production and price controls;
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the extent to which U.S. shale producers become "swing producers" adding or subtracting to the world supply totals of oil, NGL and natural gas;
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future regulations prohibiting or restricting our ability to apply hydraulic fracturing to our wells;
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current and future regulations regarding well spacing;
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prevailing prices on local oil, NGL and natural gas price indexes in the areas in which we operate;
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localized and global supply and demand fundamentals and transportation availability;
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weather conditions;
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technological advances affecting energy consumption;
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the price and availability of alternative fuels; and
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domestic, local and foreign governmental regulation and taxes.
Lower oil, NGL and natural gas prices have and will continue to 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 oil, NGL and natural gas reserves as existing reserves are depleted. A continuing decrease in oil, NGL and natural gas prices could render uneconomic an even larger portion of our exploration, development and exploitation projects. This has already resulted in us having to make significant downward adjustments to our estimated proved reserves, and we may need to make further downward adjustments in the future. Furthermore, under our Senior Secured Credit Facility, scheduled borrowing base redeterminations occur on each May 1 and November 1, and the lenders have the right to call for an interim redetermination of the borrowing base one time between any two redetermination dates and in other specified circumstances. We expect that the extended decline in oil, NGL and natural gas prices will adversely impact our borrowing base in future borrowing base redeterminations, which could trigger repayment obligations under the Senior Secured Credit Facility to the extent our outstanding loans under the Senior Secured Credit Facility exceed the redetermined borrowing base and otherwise materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. In addition, lower oil, NGL and natural gas prices may cause a further decline in our stock price.
Currently, we receive incremental cash flows as a result of our hedging activity. To the extent we are unable to obtain future hedges at attractive prices or our derivative activities are not effective, our cash flows and financial condition may be adversely impacted.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, NGL and natural gas, we enter into derivative instrument contracts for a portion of our oil, NGL and natural gas production, including swaps, collars, puts and basis swaps. In accordance with applicable accounting principles, we are required to record our derivatives at fair market value, and they are included on our consolidated balance sheet as assets or liabilities and in our consolidated statements of operations as gain (loss) on derivatives. Gain (loss) on derivatives are included in our cash flows from operating activities. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair market value of our derivative instruments. Although our current hedges provide us with a benefit as they are priced above the current depressed prices for oil, NGL and natural gas, as these hedges expire, there is significant uncertainty that we will be able to put new hedges in place that will provide us with similar benefit.
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 counter-party 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.
For additional information regarding our hedging activities, please see "Item 7. Management's discussion and analysis of financial condition and results of operations-Results of operations-Commodity derivatives."
Estimating reserves and future net revenues involves uncertainties. Decreases in oil, NGL and natural gas prices, increases in service costs or negative revisions to reserve estimates or assumptions as to future oil, NGL and natural gas prices, may lead to decreased earnings and losses or impairment of oil, NGL and natural gas assets.
The reserve data included in this Annual Report represent estimates. Reserves estimation is a subjective process of evaluating underground accumulations of oil, NGL and natural gas that cannot be measured in an exact manner. Reserves that are "proved reserves" are those estimated quantities of oil, NGL and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable in future years from known reservoirs under existing economic and operating conditions and that relate to specific locations for which the extraction of hydrocarbons must have commenced or the operator must be reasonably certain will commence within a five-year period.
The estimation process relies on interpretations of available geological, geophysical, engineering and production data. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of developmental expenditures, including higher decline curves in the first year of production and many other factors beyond the control of the producer. In addition, the estimates of future net revenues from our proved reserves and the present value of such estimates are based upon certain assumptions about future production levels, prices and costs that may not prove to be correct. Further, initial production rates reported by us or other operators may not be indicative of future or long-term production rates. A production decline may be rapid and irregular when compared to a well's initial production.
Quantities of proved reserves are estimated based on economic conditions in existence during the period of assessment. Changes to oil, NGL and natural gas prices in the markets for such commodities may have the impact of shortening the economic lives of certain fields because it becomes uneconomic to produce all recoverable reserves on such fields, which reduces proved property reserves estimates. In 2015, negative revisions of 124,180 MBOE of previously estimated quantities are primarily attributable to the removal of 106,883 MBOE due to the combined effect of the removal of 378 proved undeveloped locations and the net effect of reinterpreting 34 undeveloped locations. The 378 locations that were removed were comprised of 182 vertical Wolfberry wells due to lower commodity prices and 196 horizontal wells to better align the timing of their development with our future drilling plans. The remaining 17,297 MBOE of negative revisions are due to a combination of pricing, performance and other changes to the proved developed producing and proved developed non-producing wells.
Negative revisions in the estimated quantities of proved reserves have the effect of increasing the rates of depletion on the affected properties, which decrease earnings or result in losses through higher depletion expense. These revisions, as well as revisions in the assumptions of future cash flows of these reserves, may also trigger impairment losses on certain properties, which would result in a non-cash charge to earnings. See Note 20.d to our consolidated financial statements included elsewhere in this Annual Report.
Also, the substantial decrease in oil, NGL and natural gas prices has had the effect of rendering uneconomic a portion of our exploration, development and exploitation projects. This resulted in our having to make downward adjustments to our estimated proved reserves. It is possible that we may need to make additional downward adjustments in the future (which could be significant).
As a result of the sustained decrease in prices for oil, NGL and natural gas, we have taken and may be required to take further 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 prevailing commodity prices and 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 have been required to, and may be required to further, write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings.
Oil, NGL and natural gas prices have significantly declined since mid-2014 and have remained low in the first-quarter of 2016. Primarily as a result of these lower prices, our December 31, 2015 estimated proved reserves decreased 171 MMBOE from our December 31, 2014 reserves, converted to three streams. Additionally, we recorded non-cash full cost ceiling impairments of $488.0 million, $906.4 million and $975.0 million in the second, third and fourth quarters of 2015, respectively. If prices remain at or below current levels and all other factors remain the same, we will incur further charges in the future. Such charges could have a material adverse effect on our results of operations for the periods in which they are taken. See Note 2.g to our consolidated financial statements included elsewhere in this Annual Report for additional information.
Any significant reduction in our borrowing base under our Senior Secured Credit Facility as a result of a periodic borrowing base redetermination or otherwise will negatively impact our liquidity and, consequently, our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our Senior Secured Credit Facility or any other obligation if required as a result of a borrowing base redetermination.
Availability under our Senior Secured Credit Facility is currently subject to a borrowing base of $1.15 billion. The borrowing base is subject to scheduled semiannual (May 1 and November 1) and other elective borrowing base redeterminations based upon, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the Senior Secured Credit Facility. The lenders under our Senior Secured Credit Facility can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under our Senior Secured Credit Facility. Reductions in estimates of our oil, NGL and natural gas reserves will result in a reduction in our borrowing base (if prices are kept constant). Given the ongoing decline in commodity prices for oil, NGL and natural gas, it is likely that reductions in our borrowing base could also arise from other factors, including but not limited to:
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lower commodity prices or production;
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increased leverage ratios;
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inability to drill or unfavorable drilling results;
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changes in crude oil, NGL and natural gas reserve engineering;
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increased operating and/or capital costs;
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the lenders' inability to agree to an adequate borrowing base; or
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adverse changes in the lenders' practices (including required regulatory changes) regarding estimation of reserves.
As of February 16, 2016, we had $170.0 million of borrowings outstanding under our Senior Secured Credit Facility. We may make further borrowings under our Senior Secured Credit Facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise will negatively impact our liquidity and our ability to fund our operations and, as a result, would have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our Senior Secured Credit Facility were to exceed the borrowing base as a result of any such redetermination, we could be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.
Our business requires significant capital expenditures and we may be unable to obtain needed capital or financing on satisfactory terms or at all.
Our exploration, development, marketing, transportation and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations,
borrowings on our Senior Secured Credit Facility, equity offerings and proceeds from the sale of our Senior Unsecured Notes. We do not have commitments from anyone to contribute capital to us. Future cash flows are subject to a number of variables, including the level of production from existing wells, prices of oil, NGL and natural gas and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may have limited ability to obtain the additional capital necessary to sustain our operations at current levels. We may not be able to obtain debt or equity financing on terms favorable to us or at all. The failure to obtain additional capital could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a decline in our oil, NGL and natural gas production or reserves and, in some areas, a loss of properties.
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 our cash flow and/or liquidity available for drilling and place us at a competitive disadvantage. For example, as of February 16, 2016 we had $1.0 billion of elected commitment on our Senior Secured Credit Facility, subject to compliance with financial covenants. The impact of a 1.0% increase in interest rates on an assumed borrowing of the full $1.0 billion elected commitment on our Senior Secured Credit Facility would result in increased annual interest expense of $10.0 million and a decrease in our net income before income taxes. 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 our 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 have incurred losses from operations for various periods since our inception and may do so in the future.
We incurred net losses from our inception to December 31, 2006 of $1.8 million and for each of the years ended December 31, 2007, 2008, 2009 and 2015 of $6.1 million, $192.0 million, $184.5 million and $2.2 billion, respectively. Our development of and participation in an increasingly larger number of locations has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this section may impede our ability to economically find, develop, exploit and acquire oil, NGL and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows from operating activities in the future. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Critical accounting policies and estimates."
We require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.
Our ability to make payments on and to refinance our indebtedness and to fund planned capital expenditures depends on our ability to generate cash in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. We cannot assure you that we will generate sufficient cash flow from operations or that future funding will be available to us under our Senior Secured Credit Facility, equity offerings or other actions in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness at or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness on commercially reasonable terms or at all.
Our debt agreements contain restrictions that limit our flexibility in operating our business.
Our Senior Secured Credit Facility and the indentures governing our Senior Unsecured Notes each contain, and any future indebtedness we incur may contain, various covenants that limit our ability to engage in specified types of transactions. These covenants limit our ability to, among other things:
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incur additional indebtedness;
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pay dividends on, repurchase or make distributions in respect of our capital stock or make other restricted payments;
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make certain investments;
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sell certain assets;
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create liens;
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consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; and
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enter into certain transactions with our affiliates.
As a result of these covenants, we are limited in the manner in which we may conduct our business and we may be
unable to engage in favorable business activities or finance future operations or our capital needs. In addition, the covenants in our Senior Secured Credit Facility require us to maintain a minimum working capital ratio and minimum interest coverage ratio and also limit our capital expenditures. A breach of any of these covenants could result in a default under one or more of these agreements, including as a result of cross default provisions and, in the case of our Senior Secured Credit Facility, permit the lenders to cease making loans to us. Upon the occurrence of an event of default under our Senior Secured Credit Facility, the lenders could elect to declare all amounts outstanding under our Senior Secured Credit Facility to be immediately due and payable and terminate all commitments to extend further credit. Such actions by those lenders could cause cross defaults under our other indebtedness, including the Senior Unsecured Notes. If we were unable to repay those amounts, the lenders under our Senior Secured Credit Facility could proceed against the collateral granted to them to secure that indebtedness. We pledged a significant portion of our assets as collateral under our Senior Secured Credit Facility. If the lenders under our Senior Secured Credit Facility accelerate the repayment of the borrowings thereunder, the proceeds from the sale or foreclosure upon such assets will first be used to repay debt under our Senior Secured Credit Facility, and we may not have sufficient assets to repay our unsecured indebtedness thereafter.
If we were to experience an ownership change, we could be limited in our ability to use net operating losses arising prior to the ownership change to offset future taxable income. In addition, our ability to use net operating loss carry forwards to reduce future tax payments may be limited if our taxable income does not reach sufficient levels.
As of December 31, 2015, we had a net operating loss ("NOL") carryforward for federal income tax purposes of $1.4 billion. If we were to experience an "ownership change," as determined under Section 382 of the Internal Revenue Code of 1986, as amended (the "Code"), our ability to offset taxable income arising after the ownership change with NOLs arising prior to the ownership change would be limited, possibly substantially. An ownership change would establish an annual limitation on the amount of our pre-change NOL we could utilize to offset our taxable income in any future taxable year to an amount generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax-exempt rate. In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more "5% shareholders" (as defined in the Code) at any time during a rolling three-year period. In addition, under the Code, NOL can generally be carried forward to offset future taxable income for a period of 20 years. Our ability to use our NOL during this period will be dependent on our ability to generate taxable income, and the NOL could expire before we generate sufficient taxable income. As of December 31, 2015, based on evidence available to us, including projected future cash flows from our oil and natural gas reserves and the timing of those cash flows, we believe a portion of our NOL is not fully realizable. As a result, as of December 31, 2015 a valuation allowance has been recorded against our NOL tax assets.
The potential drilling locations for our future wells that we have tentatively internally identified will be drilled, if at all, over many years. This makes them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling, which in certain instances could prevent production prior to the expiration date of leases for such locations.
Although our management team has established certain potential drilling locations as a part of our long-range planning related to future drilling activities on our existing acreage, our ability to drill and develop these locations depends on a number of uncertainties, including oil, NGL and natural gas prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results (including the impact of increased horizontal drilling and longer laterals), lease expirations, gathering systems, marketing and pipeline transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous potential drilling locations we have currently identified will ever be drilled or if we will be able to produce oil, NGL or natural gas from these or any other potential 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. As such, it is likely our actual drilling activities, especially in the long term, could materially differ from those presently anticipated.
Drilling for and producing oil, NGL and natural gas are high-risk activities with many uncertainties that could 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 exploration, exploitation, development and production activities. Our oil, NGL and natural gas exploration, exploitation, development and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil, NGL and natural gas production. Our decisions to purchase, explore, develop or otherwise exploit locations or properties will depend in part on the evaluation of information obtained through geophysical and geological analyses, production data, engineering studies and our Earth Model, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see "-Estimating reserves and future net revenues involves uncertainties. Decreases in oil, NGL and natural gas prices, or negative revisions to reserves estimates or assumptions as to future oil, NGL and natural gas prices, may lead to decreased earnings, losses or impairment of oil, NGL and natural gas
assets." 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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declines in oil, NGL and natural gas prices;
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limited availability of financing or capital at acceptable rates or terms;
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limitations in the market for oil, NGL and natural gas;
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delays imposed by or resulting from compliance with regulatory and contractual requirements and related lawsuits, which may include limitations on hydraulic fracturing or the discharge of greenhouse gases;
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pressure or irregularities in geological formations;
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shortages of or delays in obtaining equipment and qualified personnel;
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equipment failures or accidents;
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fires and blowouts;
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adverse weather conditions, such as hurricanes, blizzards and ice storms; and
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title problems.
We are involved as a passive minority-interest partner in joint ventures and are subject to risks associated with joint venture partnerships.
We are involved as a passive minority-interest partner in joint venture relationships and may initiate future joint venture projects. Entering into a joint venture as a passive minority-interest partner involves certain risks that include: the need to contribute funds to the joint venture to support its operating and capital needs; the inability to exercise voting control over the joint venture; economic or business interests that are not aligned with our venture partners, including the holding period and timing of ultimate sale of the ventures' underlying assets; and the inability for the venture partner to fulfill its commitments and obligations due to financial or other difficulties. Our interest in Medallion is as a passive minority-interest partner.
In many instances (including Medallion), we depend on the venture partner for elements of the arrangements that are important to the success of the joint venture, such as agreed payments of substantial development costs pertaining to the joint venture and its share of other costs of the joint venture. The performance of these venture partner obligations or the ability of the venture partner to meet its obligations under these arrangements is outside our control. If the venture partner does not meet or satisfy its obligations under these arrangements, the performance and success of these arrangements, and their value to us, may be adversely affected.
If our current or future venture partners are unable to meet their obligations because of insolvency, bankruptcy or other reasons, we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In addition, the insolvency of a venture partner could result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the joint venture’s suppliers and vendors and to other third parties. In such cases, we may also be required to enforce our rights, which may cause disputes among our venture partners and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, the joint ventures and/or our ability to enter into future joint ventures. Likewise, we may have similar obligations to third parties for properties we operate.
Some of our drilling and development activities are subject to joint ventures or operations controlled by third parties, which could negatively impact our control over these operations and have a material adverse effect on our business, results of operations, financial condition and prospects.
A portion of our drilling and development activities is conducted through joint operating agreements under which we own partial interests in oil and natural gas properties. If we do not operate the properties in which we own an interest, (i) we have limited ability to influence or control the day-to-day operation of such properties, including compliance with environmental, safety and other regulations, (ii) we cannot control the amount of capital expenditures that we are required to fund with respect to properties or the future development plans for the properties, (iii) we are dependent on third parties to fund their required share of capital expenditures the same as our dependency on third parties where we are the operator and (iv) we may have restrictions or limitations on our ability to sell our interests in these jointly owned assets. The failure of an operator of our wells to adequately perform operations or an operator's breach of the applicable agreements could materially reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator's timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology. Because we do not have a majority interest in most wells that we do not operate, we may not be in a position to remove the operator in the event of poor performance.
In addition, the insolvency of an operator of any of our properties, the failure of an operator of any of our properties to adequately perform operations or an operator’s breach of applicable agreements could reduce our production and revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements, to the operator's suppliers and vendors and to royalty owners under oil and gas leases jointly owned with the operator or another insolvent owner. Finally, an operator of our properties may have the right, if another non-operator fails to pay its share of costs because of its insolvency or otherwise, to require us to pay our proportionate share of the defaulting party's share of costs.
The inability of our significant customers to meet their obligations to us may materially adversely affect our financial results.
In addition to credit risk related to receivables from commodity derivative contracts, our principal exposure to credit risk is through net joint operations receivables ($21.4 million as of December 31, 2015) and the sale of our oil, NGL and natural gas production ($25.6 million in receivables as of December 31, 2015), which we market to energy marketing companies, refineries and affiliates. Joint interest receivables arise from billing entities who own partial interests 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 are generally unable to control which co-owners participate in our wells. We are also subject to credit risk due to the concentration of our oil, NGL and natural gas production receivables with several significant customers. The largest purchaser of our oil, NGL and natural gas production accounted for 37.5% of our total oil, NGL and natural gas revenues for the year ended December 31, 2015 and our sales of purchased oil are made to one customer. See Note 11 to our consolidated financial statements included elsewhere in this Annual Report for additional information. The inability or failure of our significant customers or joint working interest owners to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial results. Current economic circumstances may further increase these risks.
Our operations are substantially dependent on the availability, use and disposal of water. New legislation and regulatory initiatives or restrictions relating to water disposal wells could have a material adverse effect on our future business, financial condition, operating results and prospects.
Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. During the past several years, Texas has experienced the lowest inflows of water in recent history. As a result of these conditions, some local water districts may begin restricting the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, NGL and natural gas, which could have an adverse effect on our results of operations, cash flows and financial condition.
Additionally, our drilling procedures produce large volumes of water that we must properly dispose. The Clean Water Act of 1977, as amended, the Safe Drinking Water Act of 1974, as amended, the Oil Pollution Act of 1990, as amended, and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other natural gas wastes, into federal and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the U.S. Environmental Protection Agency (the "EPA") or the state. Furthermore, the State of Texas maintains groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. The underground injection of fluids is subject to permitting and other requirements under state laws and regulation. Obtaining permits has the potential to delay the development of oil, NGL and natural gas projects. These same regulatory programs also limit the total volume of water that can be discharged, hence limiting the rate of development, and require us to incur compliance costs. In October 2014, the RRC adopted new regulations effective as of November 17, 2014 that require additional supporting documentation, including records from the U.S. Geological Survey regarding previous seismic events in the area, as part of applications for new disposal wells. The new regulations also clarify the RRC's ability to modify, suspend or terminate a disposal well permit if scientific data indicates it is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal sites.
Moreover, the EPA is examining regulatory requirements for "indirect dischargers" of wastewater - i.e., those that send their discharges to private or publicly owned treatment facilities, which treat the wastewater before discharging it to regulated waters. On April 7, 2015, the EPA published a proposed rule establishing federal pre-treatment standards for wastewater discharged from onshore unconventional oil and gas extraction facilities to publicly owned treatment works ("POTWs"). The EPA asserts that wastewater from such facilities can be generated in large quantities and can contain constituents that may disrupt POTW operations and/or be discharged, untreated, from the POTW to receiving waters. If adopted, the new pre-treatment rule would require unconventional oil and gas facilities to pre-treat wastewater before transferring it to POTWs. The public comment period ended on July 17, 2015, and the EPA is expected to publish a final rule by August 2016. The EPA is also
conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.
Because of the necessity to safely dispose of water produced during drilling and production activities, these regulations, or others like them, could have a material adverse effect on our future business, financial condition, operating results and prospects. See "Item 1. Business-Regulation of the oil and natural gas industry" for a further description of the laws and regulations that affect us.
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal wells could prohibit projects or result in materially increased costs and additional operating restrictions or delays because of the significance of hydraulic fracturing and water disposal wells in our business.
Hydraulic fracturing is a practice that is used to stimulate production of oil and/or natural gas from tight formations. The process involves the injection of water, propants and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Nearly all of our proved non-producing and proved undeveloped reserves associated with future drilling, recompletion and refracture stimulation projects require hydraulic fracturing. If we are unable to apply hydraulic fracturing to our wells or the process is prohibited or significantly regulated or restricted, we would lose the ability to (i) drill and complete the projects for such proved reserves and (ii) maintain the associated acreage, which would have a material adverse effect on our future business, financial condition, operating results and prospects.
The federal Safe Drinking Water Act ("SDWA") regulates the underground injection of substances through the Underground Injection Control ("UIC") Program. However, hydraulic fracturing is generally exempt from regulation under the UIC Program, and thus the process is typically regulated by state oil and gas commissions. Nevertheless, the EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC Program. Under this assertion of authority, the EPA requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. The U.S. Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. On February 12, 2014, the EPA published a revised UIC Program guidance for oil, NGL and natural gas hydraulic fracturing activities using diesel fuel. The guidance document describes how regulations of Class II wells, which are those wells injecting fluids associated with oil, NGL and natural gas production activities, may be tailored to address the purported unique risks of diesel fuel injection during the hydraulic fracturing process. Although the EPA is not the permitting authority for UIC Class II programs in Texas, where we maintain acreage, the EPA is encouraging state programs to review and consider use of the above-mentioned guidance. Furthermore, legislation has been proposed in recent sessions of Congress to repeal the hydraulic fracturing exemption from the SDWA, provide for federal regulation of hydraulic fracturing, and require public disclosure of the chemicals used in the fracturing process.
On May 9, 2014, the EPA issued an Advanced Notice of Proposed Rulemaking seeking public comment on its intent to develop and issue regulations under the Toxic Substances Control Act regarding the disclosure of information related to the chemicals used in hydraulic fracturing. The public comment period ended on September 18, 2014. The EPA plans to develop a Notice of Proposed Rulemaking by December 2016, which would describe a proposed mechanism, regulatory, voluntary, or a combination of both, to collect data on hydraulic fracturing chemical substances and mixtures.
Also, on March 26, 2015, the Bureau of Land Management (the "BLM") published a final rule governing hydraulic fracturing on federal and Indian lands. The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water. The rule took effect on June 24, 2015, although it is the subject of several pending lawsuits filed by industry groups and at least four states, alleging that federal law does not give the BLM authority to regulate hydraulic fracturing. On September 30, 2015, the United States District Court for Wyoming issued a preliminary injunction preventing the BLM from implementing the rule nationwide. This order has been appealed to the Tenth Circuit Court of Appeals.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health. In June 2015, the EPA released its draft assessment report for peer review and public comment, finding that, while there are certain mechanisms by which hydraulic fracturing activities could potentially impact drinking water resources, there is no evidence available showing that those mechanisms have led to widespread, systemic impacts. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and
minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanism.
On August 16, 2012, the EPA published final rules that subject oil, NGL and natural gas production, processing, transmission, and storage operations to regulation under the New Source Performance Standards ("NSPS") and National Emission Standards for Hazardous Air Pollutants ("NESHAP") programs. The rule includes NSPS Standards for completions of hydraulically fractured gas wells and establishes specific new requirements for emissions from compressors, controllers, dehydrators, storage vessels, natural gas processing plants and certain other equipment. The final rule seeks to achieve a 95% reduction in volatile organic compounds ("VOC") emitted by requiring the use of reduced emission completions or "green completions" on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of these requests for reconsideration. For example, in September 2013 and December 2014, the EPA amended its rules to extend compliance deadlines and to clarify the NSPS. Further, on July 31, 2015, the EPA finalized two updates to the NSPS to address the definition of low-pressure wells and references to tanks that are connected to one another (referred to as connected in parallel). In addition, on September 18, 2015, the EPA published a suite of proposed rules to reduce methane and VOC emissions from oil and gas industry, including new "downstream" requirements covering equipment in the natural gas transmission segment of the industry that was not regulated by the 2012 rules. The public comment period closed on December 4, 2015.
Also, on January 22, 2016, the BLM announced a proposed rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The proposed rule would require operators to use currently available technologies and equipment to reduce flaring, periodically inspect their operations for leaks, and replace outdated equipment that vents large quantities of gas into the air. The rule would also clarify when operators owe the government royalties for flared gas.
These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or utilize specific equipment or technologies to control emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, pursuant to legislation adopted by the State of Texas in June 2011, the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public beginning February 1, 2012. Furthermore, on May 23, 2013, the RRC issued the "well integrity rule," which updates the RRC's Rule 13 requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The "well integrity rule" took effect in January 2014. Additionally, on October 28, 2014, the RRC adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed, new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the RRC's authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular.
If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted or laws or regulations are adopted to restrict water disposal wells, such laws could make it more difficult or costly for us to drill and produce from conventional or tight formations as well as make it easier for third parties opposing the oil, NGL and natural gas industry to initiate legal proceedings. In addition, if these matters are regulated at the federal level, fracturing and disposal activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and
also to attendant permitting delays and potential increases in costs. These developments, as well as new laws or regulations, could cause us to incur substantial compliance costs, and compliance or the consequences of failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the potential impact on our business that may arise if federal or state legislation governing hydraulic fracturing or water disposal wells are enacted into law.
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 oil, NGL and natural gas exploration, production and gathering 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. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.
See "Item 1. Business-Regulation of the oil and natural gas industry" and other risk factors described in this "Item 1A. Risk Factors" for a further description of the laws and regulations that affect us.
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil, NGL and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
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 (the "NGA") exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission ("FERC"). We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish whether a pipeline performs a gathering function and therefore is exempt from the FERC's jurisdiction under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is a fact-based determination. The classification of facilities as unregulated gathering 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, which could cause our revenues to decline and operating expenses to increase and may materially adversely affect our business, financial condition or results of operations. In addition, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting and daily scheduled flow and capacity posting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition or results of operations.
The adoption of climate change legislation or regulations restricting emissions of "greenhouse gases" could result in increased operating costs and reduced demand for the oil, NGL and natural gas we produce.
Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, through the planned development of GHG emission inventories and/or regional GHG cap and trade programs or other mechanisms. Most cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing
plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Some states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.
In addition, in December 2009, the EPA determined that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act. The motor vehicle rule, which became effective in July 2010, purports to limit emissions of GHGs from motor vehicles. The EPA adopted the stationary source rule (or the "tailoring rule") in May 2010, and it became effective in January 2011. The tailoring rule established new GHG emissions thresholds that determine when stationary sources must obtain permits under the Prevention of Significant Deterioration ("PSD") and Title V programs of the Clean Air Act. On June 23, 2014, in Utility Air Regulatory Group v. EPA ("UARG v. EPA"), the Supreme Court held that stationary sources could not become subject to PSD or Title V permitting solely by reason of their GHG emissions. The Court ruled, however, that the EPA may require installation of best available control technology for GHG emissions at sources otherwise subject to the PSD and Title V programs. On December 19, 2014, the EPA issued two memoranda providing initial guidance on GHG permitting requirements in response to the Court's decision in UARG v. EPA. In its preliminary guidance, the EPA indicated it would promulgate a rule to rescind any PSD permits issued under the portions of the tailoring rule that were vacated by the Court. In the interim, the EPA issued a narrowly crafted "no action assurance" indicating it will exercise its enforcement discretion not to pursue enforcement of the terms and conditions relating to GHGs in an EPA-issued PSD permit, and for related terms and conditions in a Title V permit. On April 30, 2015, the EPA issued a final rule allowing permitting authorities to rescind PSD permits issued under the invalid regulations.
In September 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas/distribution companies, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA published a final rule expanding the GHG reporting rule to include onshore oil, NGL and natural gas production, processing, transmission, storage and distribution facilities. This rule requires reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. In October 2015, the EPA amended the GHG reporting rule to add the reporting of GHG emissions from gathering and boosting systems, completions and workovers of oil wells using hydraulic fracturing, and blowdowns of natural gas transmission pipelines.
The EPA has continued to adopt GHG regulations applicable to other industries, such as its August 2015 adoption of three separate, but related, actions to address carbon dioxide pollution from power plants, including final Carbon Pollution Standards for new, modified and reconstructed power plants, a final Clean Power Plan to cut carbon dioxide pollution from existing power plants, and a proposed federal plan to implement the Clean Power Plan emission guidelines. Upon publication of the Clean Power Plan on October 23, 2015, more than two dozen States as well as industry and labor groups challenged the Clean Power Plan in the D.C. Circuit Court of Appeals. On February 9, 2016, the U.S. Supreme Court stayed the Clean Power Plan pending disposition of the legal challenges. Nevertheless, as a result of the continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.
In December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake "ambitious efforts" to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement, if ratified, establishes a framework for the parties to cooperate and report actions to reduce GHG emissions.
Restrictions on GHG emissions that may be imposed could adversely affect the oil and natural gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil, NGL and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.
In addition, claims have been made against certain energy companies alleging that GHG emissions from oil, NGL and
natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damages. While we are currently not a party to such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Moreover, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.
Our oil, NGL and natural gas is sold to a limited number of geographic markets so an oversupply in any of those areas could have a material negative effect on the price we receive.
Our oil, NGL and natural gas is sold to a limited number of geographic markets which each have a fixed amount of storage and processing capacity. As a result, if such markets become oversupplied with oil, NGL and/or natural gas, it could have a material negative effect on the price we receive for our products and therefore an adverse effect on our financial condition. There is a risk that refining capacity in the U.S. Gulf Coast may be insufficient to refine all of the light sweet crude oil being produced in the United States. If light sweet crude oil production remains at current levels or continues to increase, demand for our light crude oil production could result in widening price discounts to the world crude prices and potential shut-in of production due to a lack of sufficient markets despite the lift on prior restrictions on the exporting of oil and natural gas.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of federal, state and local environmental, health and safety requirements applicable to our exploration, development, marketing, transportation and production activities. These laws and regulations may require us to obtain a variety of permits or other authorizations governing our air emissions, water discharges, waste disposal or other environmental impacts associated with drilling, production and transporting product pipelines or other operations; regulate the sourcing and disposal of water used in the drilling, fracturing and completion processes; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier, seismically active areas, and other protected areas; require remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; and/or impose substantial liabilities for spills, pollution or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of oil or natural gas production. These laws and regulations are complex, change frequently and have tended to become increasingly stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. In addition, accidental spills or releases from our operations could expose us to significant liabilities under environmental laws. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil, NGL and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
See "Item 1. Business-Regulation of environmental and occupational health and safety matters" for a further description of the laws and regulations that affect us.
If we are unable to drill new allocation wells it could have a material adverse impact on our future production results.
In the State of Texas, allocation wells allow an oil and gas producer to drill a horizontal well under two or more leaseholds that are not pooled. We are active in drilling and producing allocation wells. If there are regulatory changes with regard to allocation wells, the RRC denies or significantly delays the permitting of allocation wells or if legislation is enacted that negatively impacts the current process under which allocation wells are currently permitted, it could have an adverse impact on our ability to drill long horizontal lateral wells on some of our leases, which in turn could have a material adverse impact on our anticipated future production.
Unless we replace our oil, NGL and natural gas production, our reserves and production will continue to decline, which would adversely affect our future cash flows and results of operations.
Producing oil, NGL and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration, development and exploitation activities or continually acquire properties containing proved reserves, our proved reserves will continue to decline as those reserves are produced. Our future oil, NGL and 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, exploit, 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.
A decrease in our production of oil, NGL and natural gas could negatively impact our ability to meet our contractual obligations to deliver oil, NGL and natural gas and our ability to retain our leases.
A portion of our oil, NGL and gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss or unavailability of pipeline or gathering system access and capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions, including low oil, NGL and gas prices. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners to maintain our leases.
In addition, we have entered into agreements with third party shippers, including Medallion, and purchasers that require us to deliver minimum amounts of crude oil and natural gas. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil we acquire, over the next ten years. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements or we may have to purchase oil from third parties to fulfill our delivery obligations. This could adversely impact our cash flows, profit margins and net income.
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.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil, NGL and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil, NGL and natural gas, including the possibility of:
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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater 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 oil, NGL and natural gas related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
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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 and associated clean-up responsibilities;
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regulatory investigations, penalties or other sanctions;
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suspension of our operations; and
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repair and remediation costs.
We may elect not to obtain insurance 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.
The marketability of our production is dependent upon transportation and other facilities, certain of which we do not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.
The marketability of our oil, NGL and natural gas production depends on a variety of factors, including the availability, proximity, capacity and quality constraints of transportation and storage facilities owned by us or third parties. We do not control many of the trucks and other third-party transportation facilities necessary for the transportation of our products and our access to them may be limited or denied. Our failure to provide or obtain such services on acceptable terms could materially harm our business.
Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil, NGL and natural gas and thereby cause a significant interruption in our operations. The crude oil pipelines that transport our crude oil to market have quality specifications, including a Reid Vapor Pressure ("RVP") specification. While our tank batteries and equipment are designed to deliver crude oil that meets all pipeline specifications, including RVP, there is a risk that our crude oil production at any of our tank batteries could have an RVP that exceeds the pipeline specifications. The pipelines have the right under their tariffs to request that crude oil that does not meet their quality specifications, including RVP, be shut in until such crude is brought within quality specifications. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or specifications or encounter production related difficulties, we may be required to shut in or curtail production. Any such shut-in or curtailment, or an inability to obtain favorable terms for delivery of the oil, NGL and natural gas produced from our fields, could materially and adversely affect our financial condition and results of operations.
Derivatives reform legislation and related regulations could have an adverse effect on our ability to hedge risks associated with our business.
The July 2010 Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market and mandates that the Commodity Futures Trading Commission (the "CFTC"), the SEC, and federal regulators of financial institutions (the "Prudential Regulators") adopt rules or regulations implementing the Dodd-Frank Act and providing definitions of terms used in the Dodd-Frank Act. The Dodd-Frank Act establishes margin requirements and requires clearing and trade execution practices for certain market participants and may result in certain market participants needing to curtail or cease their derivatives activities.
Although some of the rules necessary to implement the Dodd-Frank Act remain to be adopted, the CFTC, the SEC and the Prudential Regulators have issued many rules to implement the Dodd-Frank Act, including a rule, which we refer to as the "Mandatory Clearing Rule," requiring clearing of hedges, or swaps, that are subject to it (currently, only certain interest rate and credit default swaps, which we do not presently have), a rule, which we refer to as the "End User Exception," establishing an "end user" exception to the Mandatory Clearing Rule, a rule, which we refer to as the "Margin Rule," setting forth collateral requirements in connection with swaps that are not cleared and also an exception to the Margin Rule for end users that are not financial end users, which exception we refer to as the "Non-Financial End User Exception," and a rule, subsequently vacated by the United States District Court for the District of Columbia and remanded to the CFTC for further proceedings, imposing position limits. The CFTC proposed a new version of this rule, which we refer to as the "Re-Proposed Position Limit Rule," with respect to which the comment period has closed but a final rule has not been issued.
We qualify for the End User Exception and will utilize it if the Mandatory Clearing Rule is expanded to cover swaps in which we participate, we qualify for the Non-Financial End User Exception and will not be required to post margin in connection with uncleared swaps under the Margin Rule, and the quantities under the swaps in which we participate are well within applicable limits under the Re-Proposed Position Limit Rule, so we do not expect to be directly affected by any of such rules. However, most if not all of our hedge counterparties will be subject to mandatory clearing in connection with their hedging activities with parties who do not qualify for the End User Exception and will be required to post margin in connection with their hedging activities with other swap dealers, major swap participants, financial end users and other persons that do not qualify for the Non-Financial End User Exception. In addition, the European Union and other non-U.S. jurisdictions have enacted laws and regulations, which we refer to collectively as "Foreign Regulations" which may apply to our transactions with counterparties subject to such Foreign Regulations. The Dodd-Frank Act, the rules which have been adopted and not vacated, and, to the extent that the Re-Proposed Position Limit Rule is effected, such proposed rule could significantly increase the cost of our derivative contracts, materially alter the terms of our derivative contracts, reduce the availability of derivatives to us that we have historically used to protect against risks that we encounter in our business, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Foreign Regulations could have similar effects. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations and Foreign 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 contracts related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition, and our results of operations.
Our producing properties are in a concentrated geographic area, making us vulnerable to risks associated with operating in one major geographic area.
Our producing properties are geographically concentrated in the Permian Basin. At December 31, 2015, 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 or natural gas.
Seasonal weather conditions and lease stipulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil, NGL and natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and lease stipulations designed to protect various wildlife. This limits our ability to operate in those areas and can later intensify competition during certain 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. In addition, the Permian Basin has recently experienced severe winter weather and, as a consequence, our operating results during similar periods may ultimately be adversely affected.
Our use of 2D and 3D seismic and other data, including our Earth Model, is subject to interpretation and may not accurately identify the presence of oil, NGL and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, 2D and 3D seismic data and other data, such as that incorporated into our Earth Model that provide either visualization techniques and/or statistical analyses are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures or the amount of hydrocarbons. We employ 3D seismic technology with respect to certain of our projects. The implementation and practical use of 3D seismic technology is relatively unproven, which can lessen its effectiveness, at least in the near term, and increase our costs. In addition, the use of 3D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and exploration expenses as a result of such expenditures, which may result in a reduction in our returns. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.
The Earth Model is reliant upon data that is subject to interpretation and is itself the product of interpretation. Therefore, there is no guarantee that the data it produces or our interpretation of that data will be correct. The Earth Model is a new process and there is no guarantee that the initial rates of correlation will be duplicated.
We often gather 3D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 3D data without having an opportunity to attempt to benefit from those expenditures.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services as well as fees for the cancellation of such services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for and availability of qualified and experienced 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 oil, NGL and natural gas prices, causing periodic shortages. From time to time, 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. In particular, in recent years the high level of drilling activity in the Permian Basin has resulted in equipment shortages in those areas. We have committed in the past, and we may in the future commit, to drilling contracts with various third parties that contain penalties for early terminations. These penalties could negatively impact our financial statements upon contract termination. Rig shortages as well as rig related fees could result in delays 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.
Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil, NGL and natural gas and secure trained personnel.
Our ability to acquire additional locations and to find and develop reserves in the future may depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil, NGL and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil, NGL and natural gas industry, especially in our focus areas. 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 oil, NGL and natural gas properties and exploratory locations and to evaluate, bid for and purchase a greater number of properties and locations 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. 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.
Technological advancements and trends in our industry affect the demand for certain types of equipment.
Technological advancements and trends in our industry affect the demand for certain types of equipment. Especially in times when commodity prices are high, the demand for drilling rigs that are able to drill horizontally in the Permian Basin increases. In addition, oil and gas exploration and production companies have increased the use of "pad drilling" in recent years whereby a series of horizontal wells are drilled in succession by walking or skidding a drilling rig at a single-site location. If we are unable to secure such rigs in a timely or cost-efficient manner it 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. The loss of the services of our senior management or technical personnel, including Randy Foutch, our Chairman and Chief Executive Officer, could have a material adverse effect on our operations. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
A significant reduction by Warburg Pincus of its ownership interest in us could adversely affect us.
Warburg Pincus is our largest stockholder and two members of our board of directors are affiliates of Warburg Pincus. As of December 31, 2015, Warburg Pincus owned 41.0% of our outstanding common stock. We believe that Warburg Pincus' substantial ownership interest in us provides them with an economic incentive to assist us to be successful. However, Warburg Pincus is not obligated to maintain its ownership interest in us and may elect at any time to change its ownership position in our stock. If Warburg Pincus sells all or a substantial portion of its ownership interest in us, Warburg Pincus may have less incentive to assist in our success and its affiliates that are members of our board of directors may resign. Such actions could
adversely affect our ability to successfully implement our business strategies, which could adversely affect our cash flows or results of operations.
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 oil, NGL and natural gas prices and their applicable differentials;
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timing of development;
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capital and operating costs; and
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potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. Our assessment 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 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. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be able to fulfill its contractual obligations. Problems with properties we acquire could have a material adverse effect on our business, financial condition and results of operations.
We may incur significant additional amounts of debt.
As of February 16, 2016, we had total long-term indebtedness of $1.5 billion. In addition, we may be able to incur substantial additional indebtedness, including secured indebtedness, in the future. The restrictions on the incurrence of additional indebtedness contained in the indentures governing our Senior Unsecured Notes and in our Senior Secured Credit Facility are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we face would increase and may make it more difficult to satisfy our existing financial obligations. In addition, the restrictions on the incurrence of additional indebtedness contained in the indentures governing the Senior Unsecured Notes apply only to debt that constitutes indebtedness under the indentures.
We may incur more taxes and certain of our projects may become uneconomic if certain federal income tax deductions currently available with respect to oil and natural gas exploration and development are eliminated as a result of future legislation.
Legislation has been proposed that would, if enacted, eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to (i) the repeal of the percentage depletion allowance for oil and natural 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 and (iv) an extension of the amortization period for certain geological and geophysical expenditures. In addition, the President of the United States recently proposed adding a $10.25 per Bbl tax on crude oil produced in the United States. It is unclear whether any of the foregoing changes will actually be enacted or how soon any such changes could become effective. Any such change or similar other change could materially adversely affect our financial condition and results of operations by increasing the costs we incur which would in turn make it uneconomic to drill some locations if commodity prices are not sufficiently high, resulting in lower revenues and decreases in production and reserves.
Loss of our information and computer systems could adversely affect our business.
We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure or we were subject to cyberspace breaches or attacks, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, NGL and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.
Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.
As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include, but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. Although we utilize various procedures and controls to monitor and protect against these threats and to mitigate our exposure to such threats, there can be no assurance that these procedures and controls will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows.
Risks relating to our common stock
The concentration of our capital stock ownership among our largest stockholder will limit other stockholders' ability to influence corporate matters.
As of December 31, 2015, Warburg Pincus owned 41.0% of our outstanding common stock. Consequently, Warburg Pincus has significant influence over all matters that require approval by our stockholders, including the election of directors and approval of significant corporate transactions. This concentration of ownership limits the ability of other stockholders to influence corporate matters.
Furthermore, conflicts of interest could arise in the future between us, on the one hand, and Warburg Pincus and its affiliates, including its portfolio companies, on the other hand, concerning among other things, potential competitive business activities or business opportunities. Warburg Pincus LLC is a private equity firm that has invested in, among other things, companies in the energy industry. As a result, Warburg Pincus' existing and future portfolio companies which it controls may compete with us for investment or business opportunities. These conflicts of interest may not be resolved in our favor.
We have also renounced our interest in certain business opportunities. Our amended and restated certificate of incorporation provides that, to the fullest extent permitted by applicable law, we renounce any interest or expectancy in any business opportunity, transaction or other matter in which Warburg Pincus or any private fund that it manages or advises, any of their respective officers, directors, partners and employees, and any portfolio company in which such persons or entities have an equity interest (other than us and our subsidiaries) (each, a "specified party") participates or desires or seeks to participate and that involves any aspect of the energy business or industry, even if the opportunity is one that we might reasonably have pursued or had the ability or desire to pursue if granted the opportunity to do so, and no such specified party shall be liable to us for breach of any fiduciary or other duty, as a director or officer or controlling stockholder or otherwise, by reason of the fact that such specified party pursues or acquires any such business opportunity, directs any such business opportunity to another person or fails to present any such business opportunity, or information regarding any such business opportunity, to us. Notwithstanding the foregoing, we do not renounce any interest or expectancy in any business opportunity, transaction or other matter that is offered in writing solely to (i) one of our directors or officers who is not also a specified party or (ii) a specified party who is one of our directors, officers or employees and is offered such business opportunity solely in his or her capacity as our director, officer or employee. By renouncing our interest and expectancy in any business opportunity that from time to time may be presented to Warburg Pincus and its affiliates, our business and prospects could be adversely affected if attractive business opportunities are procured by such parties for their own benefit rather than for ours.
Our amended and restated certificate of incorporation, amended and restated bylaws, and Delaware state law contain provisions that may have the effect of delaying or preventing a change in control and may adversely affect the market price of our capital stock.
Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without any further vote or action by the stockholders. The rights of the holders of our common stock will be subject to the rights of the holders of any preferred stock that may be issued in the future. The issuance of preferred stock could delay, deter or prevent a change in control and could adversely affect the voting power or economic value of our shares.
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 ability of our stockholders to call special meetings;
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a separate vote of 75% of the voting power of the outstanding shares of capital stock in order for stockholders to amend the bylaws in certain circumstances;
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our board of directors is divided into three classes with each class serving staggered three-year terms;
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stockholders do not have the right to take any action by written consent; and
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advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.
Delaware law prohibits us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who owns 15% of our stock cannot acquire us for a period of three years from the date such stockholder became an interested stockholder, unless various conditions are met, such as the approval of the transaction by our board of directors. Warburg Pincus, however, is not subject to this restriction.
The availability of shares for sale in the future could reduce the market price of our common stock.
Our board of directors has the authority, without action or vote of our stockholders, to issue all or any part of our authorized but unissued shares of common stock. In the future, we may issue securities to raise cash for acquisitions, to pay down debt, to fund capital expenditures or general corporate expenses, in connection with the exercise of stock options or to satisfy our obligations under our incentive plans. We may also acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We may also issue securities convertible into, exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our Company, reduce our earnings per share and have an adverse impact on the price of our common stock.
Because we have no plans to pay, and are currently restricted from paying dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in our Senior Secured Credit Facility and the indentures governing our Senior Unsecured Notes restrict the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.
Item 1B.
Item 1B. Unresolved Staff Comments
During 2015, the SEC issued comment letters relating to the Company's previously filed annual report on Form 10-K for the fiscal year ended December 31, 2014 inquiring about the potential impact of current commodity prices and our development plans for our reserves. The Company responded to these comment letters and was notified by the SEC that it completed its review on February 11, 2016. No amendments to any prior filings were required.
Item 2.
Item 2. Properties
The information required by Item 2. is contained in "Item 1. Business".
Item 3.
Item 3. Legal Proceedings
From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. As of the date hereof, we are not party to any legal proceedings that we currently believe will have a material adverse effect on our business, financial position, results of operations or liquidity.
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 for Registrant's Common Equity. Our common stock is listed on the New York Stock Exchange ("NYSE") under the symbol "LPI." The following table sets forth the range of high and low sales prices of our common stock as reported by the NYSE:
On February 16, 2016, the last sale price of our common stock, as reported on the NYSE, was $4.79 per share.
Holders. As of February 12, 2016, there were 56 holders of record of our common stock.
Dividends. We have not paid any cash dividends since our inception. Covenants contained in our Senior Secured Credit Facility and the indentures governing our Senior Unsecured Notes restrict the payment of cash dividends on our common stock. See "Item 1A. Risk Factors-Risks related to our business-Our debt agreements contain restrictions that limit our flexibility in operating our business" and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Cash flows-Debt." We currently 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.
Repurchase of Equity Securities.
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(1)
Represents shares that were withheld by us to satisfy employee tax withholding obligations that arose upon the lapse of restrictions on restricted stock.
Unregistered Sales of Equity Securities and Use of Proceeds. None.
Stock Performance Graph. The following performance graph and related information shall not be deemed "soliciting material" or to be "filed" with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that we specifically request that such information be treated as "soliciting material" or specifically incorporate such information by reference into such a filing.
The performance graph below shows the cumulative total return to our common stockholders from December 15, 2011, the date on which our common stock began trading on the NYSE, through December 31, 2015, as compared to the returns on the Standard and Poor's 500 Index ("S&P 500") and the Standard and Poor's 500 Oil & Gas Exploration & Production Index ("S&P O&G E&P"). The comparison was prepared based upon the following assumptions:
1. $100 was invested in our common stock at its initial public offering price of $17 per share and invested in the S&P 500 and the S&P O&G E&P on December 15, 2011 at the closing price on such date; and
2. Dividends, if any, are reinvested.
Item 6.
Item 6. Selected Historical Financial Data
The selected historical consolidated financial data presented below is not intended to replace our 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 notes thereto 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 that could cause actual results to vary from our expectations include changes in oil, NGL and natural gas prices, the timing of planned capital expenditures, availability of acquisitions, joint ventures and dispositions, uncertainties in estimating proved reserves and forecasting production results, potential failure to achieve production from development projects, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital and financial markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, 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" and "Item 1A. Risk Factors." All amounts, dollars and percentages presented in this Annual Report are rounded and therefore approximate.
Executive overview
We are an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. Since our inception, we have grown primarily through our drilling program coupled with select strategic acquisitions and joint ventures.
Our financial and operating performance for the year ended December 31, 2015 included the following:
•
Oil, NGL and natural gas sales of $431.7 million, compared to $737.2 million for the year ended December 31, 2014;
•
Average daily sales volumes of 44,782 BOE/D, compared to 32,134 BOE/D for the year ended December 31, 2014;
•
Net loss of $2.2 billion, including an after-tax non-cash full cost ceiling impairment of $2.4 billion, compared to net income of $265.6 million for the year ended December 31, 2014; and
•
Adjusted EBITDA (a non-GAAP financial measure) of $472.3 million, compared to $597.8 million for the year ended December 31, 2014.
Three-stream reporting
As of January 1, 2015, all of our natural gas processing agreements with various processors had been modified to allow us to take title to the NGL resulting from the processing of our natural gas. This enables us to report reserves, sales volumes, prices and revenues for NGL and natural gas separately for periods after January 1, 2015. As such, our reserves as of December 31, 2015 are reported in three streams: oil, NGL and natural gas. Our sales volumes, prices and reserves as of December 31, 2014 and 2013 were reported in two streams: crude oil and liquids-rich natural gas with the economic value of the NGL in our natural gas included in the wellhead natural gas price. This change impacts the comparability of 2015 with prior periods.
Reserves and non-cash full cost ceiling impairment
Our results of operations are heavily influenced by oil, NGL and natural gas prices, which have significantly declined and have remained low. These oil, NGL and natural gas price fluctuations are caused by changes in the global and regional supply of and demand for oil, NGL and natural gas, market uncertainty, economic conditions and a variety of additional factors. Since the inception of our oil and natural gas activities, commodity prices have experienced significant fluctuations, and additional changes in commodity prices may affect the economic viability of and our ability to fund drilling projects, as well as the economic valuation and economic recovery of oil, NGL and natural gas reserves.
As discussed previously in this Annual Report, during 2015 commodity prices for crude oil, NGL and natural gas experienced sharp declines, and this downward trend has accelerated further into the first quarter of 2016, with crude oil prices reaching a twelve-year low in February 2016. We have significantly reduced our capital budget for 2016. In addition, we have purposely significantly reduced the portion of our reserves that have historically been categorized as "proved undeveloped" or "PUD." We have adjusted our long-range five-year SEC PUD bookings methodology because given the current economic price environment, coupled with (i) our efforts to develop our acreage in the most efficient manner possible and determine which
potential locations will be most profitable and (ii) the uncertain effect that such environment will have on the industry's access to the capital markets, we believe that we can optimize the value for our shareholders by maintaining greater flexibility in choosing the specific drilling locations that may yield the greatest rates of return.
As our activities to date have indicated, the majority of our acreage represents a resource play, and with the benefit of improved technology, infrastructure investments and focused cost reduction efforts, we believe we have a significant number of acreage locations to drill even at the current commodity prices. In the near-term, our goal is to drill those locations that we anticipate have the potential to provide the greatest economic return and enhance shareholder value, and we have determined that the most efficient way to accomplish this is to maintain the flexibility to choose those locations based upon our continuing insight as we drill and collect data across our acreage, regardless of SEC reserve-booking status. Reducing our future PUD commitments provides us the most flexibility to maximize our rate of return at prevailing conditions and minimize the requirement to drill wells previously assigned under very different circumstances as specific PUD locations. Accordingly, we have reduced our booked PUD locations to those we have reasonable certainty to believe that we will develop in at least a two-year time horizon while maintaining the flexibility to add new PUD locations and convert other locations to proved developed reserves as our plans deem appropriate and opportunistic.
Ryder Scott, our independent reserve engineers, estimated 100% of our proved reserves as of December 31, 2015, 2014 and 2013. As of December 31, 2015, we had 125,698 MBOE of estimated proved reserves as compared to 247,322 MBOE of estimated proved reserves as of December 31, 2014 and 203,615 MBOE of estimated proved reserves as of December 31, 2013. For prices used to value our reserves, see Note 2.g to our consolidated financial statements included elsewhere in this Annual Report. Our net book value of evaluated oil and natural gas properties exceeded the full cost ceiling amount during the second, third and fourth quarters of 2015, and as such, we recorded non-cash full cost ceiling impairments during these periods of $488.0 million, $906.4 million and $975.0 million, respectively. See Note 2.g to our consolidated financial statements included elsewhere in this Annual Report for additional discussions of our full cost impairments.
We have entered into a number of commodity derivatives, which have enabled us to offset a portion of the changes in our cash flow caused by price fluctuations on our oil and natural gas production as discussed in "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," in our case, refers to the risk of loss arising from adverse changes in oil, NGL and natural gas prices and in interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather 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 exposure
Due to the inherent volatility in oil, NGL and natural gas prices, we use commodity derivatives, such as puts, swaps, collars and basis swaps to hedge price risk associated with a significant portion of our anticipated production. By removing a portion of the price volatility associated with future production, we expect to reduce, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. We have not elected hedge accounting on these derivatives and, therefore, the gains and losses on open positions are reflected in earnings. At each period end, we estimate the fair values of our commodity derivatives using an independent third-party valuation and recognize the associated gain or loss in our consolidated statements of operations included elsewhere in this Annual Report.
The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the relevant price indices. As of December 31, 2015, a 10% change in the forward curves associated with our commodity derivatives would have changed our net positions to the following amounts:
As of December 31, 2015 and 2014, the fair values of our open derivatives contracts were $276.2 million and $312.3 million, respectively. Refer to Notes 2.f, 8 and 9 of our consolidated financial statements included elsewhere in this Annual Report for additional disclosures regarding our derivatives.
Interest rate risk
Our Senior Secured Credit Facility bears interest at a floating rate and, as of December 31, 2015, we had $135.0 million outstanding on our Senior Secured Credit Facility. Our January 2022 Notes, May 2022 Notes and March 2023 Notes bear fixed interest rates and we had $450.0 million, $500.0 million and $350.0 million outstanding, respectively, as of December 31, 2015, as shown in the table below.
Counterparty and customer credit risk
As of December 31, 2015, our principal exposures to credit risk are through receivables of (i) $276.2 million from the fair values of our open derivative contracts, (ii) $27.5 million from matured derivatives, (iii) $25.6 million from the sale of our oil, NGL and natural gas production, that we market to energy marketing companies and refineries, (iv) $21.4 million from joint-interest partners and (v) $11.8 million from midstream product sales.
We are subject to credit risk due to the concentration of (i) our oil, NGL and natural gas receivables with several significant customers and (ii) our midstream service product sales receivables with one significant customer. On occasion we require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We have entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of
our derivative counterparties, who also are lenders in our Senior Secured Credit Facility. The terms of the ISDA Agreements provide the counterparties and us with rights of offset upon the occurrence of defined acts of default by either a counterparty or us to a derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party.
Refer to Note 11 to our consolidated financial statements included elsewhere in this Annual Report for additional disclosures regarding credit risk.
Item 8.
Item 8. Financial Statements and Supplementary Data
Our consolidated financial statements and supplementary financial data are included in this Annual Report beginning on page.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process designed under the supervision of the Company's Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.
As of December 31, 2015, management assessed the effectiveness of the Company's internal control over financial reporting based on the criteria for effective internal control over financial reporting established in the 2013 "Internal Control - Integrated Framework," issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2015.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Grant Thornton LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued their report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2015. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2015, is included in this Item under the heading "Report of Independent Registered Public Accounting Firm."
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Laredo Petroleum, Inc.
We have audited the internal control over financial reporting of Laredo Petroleum, Inc. (a Delaware corporation) and subsidiaries (the "Company") as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company as of and for the year ended December 31, 2015, and our report dated February 17, 2016 expressed an unqualified opinion on those financial statements.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 17, 2016
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.
Item 9A.
Item 9A. Controls and Procedures
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 the end of the period covered by this Annual Report. 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. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2015 at the reasonable assurance level.
Design and Evaluation of Internal Control Over Financial Reporting. Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, our management has included a report of their assessment of the design and effectiveness of our internal controls over financial reporting as part of this Annual Report for the fiscal year ended December 31, 2015. Grant Thornton LLP, the Company's independent registered public accounting firm, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting. Management’s report and the independent registered public accounting firm's attestation report are included in "Item 8. Financial Statements and Supplementary Data" in this Annual Report under the caption entitled "Management’s Report on Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm," respectively, and are incorporated herein by reference.
Changes in Internal Control over Financial Reporting. There have been no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during our last fiscal quarter that have materially affected or are reasonably likely to materially affect our internal controls over financial reporting.
Item 9B.
Item 9B. Other Information
Item 5.03 Amendments to Articles of Incorporation or Bylaws; Change in Fiscal Year.
On February 10, 2016, the Company's board of directors approved and adopted the second amended and restated bylaws of the Company (as amended and restated, the "Second A&R Bylaws"). The Second A&R Bylaws became effective immediately upon approval and adoption by the Company's board of directors on February 10, 2016. Pursuant to the Second A&R Bylaws, Article IV, Section 6 (the "Amended Provision") of the Company's amended and restated bylaws was amended to provide that "one senior vice president may be designated by the board of directors to perform the duties and exercise the powers of the president in the event of the president's absence or disability." Prior to the adoption of the Second A&R Bylaws, the Amended Provision provided that "one senior vice president shall be designated by the board of directors to perform the duties and exercise the powers of the president in the event of the president's absence or disability."
The foregoing description of the Second A&R Bylaws is a summary only and is qualified in its entirety by reference to the complete text of the Second A&R Bylaws, a copy of which is attached as Exhibit 3.3 to this Annual Report and incorporated herein by reference.
Part III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
Information regarding our Code of Conduct and Business Ethics, Code of Ethics For Senior Financial Officers and Corporate Governance Guidelines for our principal executive officer and principal financial and accounting officer are described in "Item 1. Business" in this Annual Report. Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 10 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2015.
Item 11.
Item 11. Executive Compensation
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 11 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2015.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 12 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2015.
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 13 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2015.
Item 14.
Item 14. Principal Accounting Fees and Services
Pursuant to paragraph 3 of General Instruction G to Form 10-K, we incorporate by reference into this Item 14 the information to be disclosed in our definitive proxy statement, which is to be filed pursuant to Regulation 14A with the SEC within 120 days after the close of the year ended December 31, 2015.
Part IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
Our consolidated financial statements are included under Part II, Item 8 of this Annual Report. For a listing of these statements and accompanying footnotes, see "Index to Consolidated Financial Statements" on page of this Annual Report.
(a)(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements or notes thereto.
(a)(3) Exhibits
__________________________________________________________________________
* Filed herewith.
** Furnished herewith.
# Management contract or compensatory plan or arrangement.
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.
KNOWN ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Randy A. Foutch, Richard C. Buterbaugh, Kenneth E. Dornblaser and Michael T. Beyer, each of whom may act without joinder of the other, as their true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, for such person and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange 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.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Laredo Petroleum, Inc.
We have audited the accompanying consolidated balance sheets of Laredo Petroleum, Inc. (a Delaware corporation) and subsidiaries (the "Company") as of December 31, 2015 and 2014, and the related consolidated statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2015. 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. 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 audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Laredo Petroleum, Inc. and subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 14 to the consolidated financial statements, the Company has changed its method of presentation for deferred income taxes in 2015 and 2014 due to the adoption of FASB Accounting Standards Update No. 2015-17 - Balance Sheet Classification of Deferred Taxes. Additionally, as discussed in Note 14 to the consolidated financial statements, the Company has changed its method of presentation for debt issuance costs in 2015 and 2014 due to the adoption of FASB Accounting Standards Update No. 2015-03 - Simplifying the Presentation of Debt Issuance Costs.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2015, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 17, 2016, expressed an unqualified opinion.
/s/ GRANT THORNTON LLP
Tulsa, Oklahoma
February 17, 2016
Laredo Petroleum, Inc.
Consolidated balance sheets
(in thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
Laredo Petroleum, Inc.
Consolidated statements of operations
(in thousands, except per share data)
The accompanying notes are an integral part of these consolidated financial statements.
Laredo Petroleum, Inc.
Consolidated statements of stockholders' equity
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
Laredo Petroleum, Inc.
Consolidated statements of cash flows
(in thousands)
The accompanying notes are an integral part of these consolidated financial statements.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Note 1-Organization
The Company (defined below) is an independent energy company focused on the acquisition, exploration and development of oil and natural gas properties, and the transportation of oil and natural gas from such properties, primarily in the Permian Basin in West Texas. On August 1, 2013, the Company sold its properties in the Mid-Continent region of the United States (as further described below).
Laredo Petroleum, Inc. ("Laredo"), formerly known as Laredo Petroleum Holdings, Inc., was formed pursuant to the laws of the State of Delaware on August 12, 2011 for purposes of a Corporate Reorganization (defined below) and initial public offering of its common stock (the "IPO"). On December 19, 2011, Laredo Petroleum, LLC ("Laredo LLC"), a Delaware limited liability company, was merged with and into Laredo, with Laredo surviving the merger (the "Corporate Reorganization"). As a holding company, Laredo's management operations were conducted through its wholly-owned subsidiary, Laredo Petroleum, Inc. ("Laredo Inc."), a Delaware corporation, and Laredo Inc's subsidiaries, Laredo Petroleum Texas, LLC ("Laredo Texas"), a Texas limited liability company, Laredo Gas Services, LLC ("Laredo Gas"), a Delaware limited liability company, and Laredo Petroleum-Dallas, Inc. ("Laredo Dallas"), a Delaware corporation.
Effective December 31, 2013, an internal corporate reorganization was completed, which simplified the corporate structure. Two of Laredo Inc.'s subsidiaries, Laredo Texas and Laredo Dallas, were merged with and into Laredo Inc. The sole remaining wholly-owned subsidiary of Laredo Inc. at the time of the internal corporate reorganization, Laredo Gas, changed its name to Laredo Midstream Services, LLC ("LMS"). Laredo Inc. merged with and into Laredo with Laredo surviving and changing its name to "Laredo Petroleum, Inc." (the events described in this paragraph collectively, the "Internal Consolidation").
On October 24, 2014, Laredo formed Garden City Minerals, LLC ("GCM"), a Delaware limited liability company, for the purpose of holding its mineral interests. GCM is wholly owned by Laredo. GCM and LMS (together, the "Guarantors") guarantee all of Laredo's debt instruments.
In these notes, the "Company," (i) when used in the present tense, prospectively or from October 24, 2014, refers to Laredo, LMS and GCM collectively; (ii) when used for historical periods from December 31, 2013 to October 23, 2014, refers to Laredo and LMS collectively; and (iii) when used for historical periods from December 19, 2011 to December 30, 2013, refers to Laredo and its subsidiaries, collectively, unless the context indicates otherwise. All amounts, dollars and percentages presented in these consolidated financial statements and the related notes are rounded and therefore approximate.
The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties primarily in the Permian Basin in West Texas. The midstream and marketing segment provides Laredo's exploration and production segment and certain third parties with (i) products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in and around Laredo's primary production corridors, (ii) water takeaway in and around Laredo's primary production corridors and (iii) oil and natural gas takeaway optionality in the field coupled with firm service commitments to maximize Laredo's oil, natural gas liquids ("NGL") and natural gas revenues.
Note 2-Basis of presentation and significant accounting policies
a. Basis of presentation
The accompanying consolidated financial statements were derived from the historical accounting records of the Company and reflect the historical financial position, results of operations and cash flows for the periods described herein. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All material intercompany transactions and account balances have been eliminated in the consolidation of accounts. Unless otherwise indicated, the information in these notes relates to the Company's continuing operations. The Company uses the equity method of accounting to record its net interests when the Company holds 20% to 50% of the voting rights and/or has the ability to exercise significant influence but does not control the entity. Under the equity method, the Company's proportionate share of the investee's net income (loss) is included in the consolidated statements of operations. See Note 15 for additional discussion of the Company's equity method investment.
b. Use of estimates in the preparation of consolidated financial statements
The preparation of the accompanying consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions about future events. These estimates and the underlying assumptions affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
and the reported amounts of revenues and expenses during the reporting period. Although management believes these estimates are reasonable, actual results could differ.
Significant estimates include, but are not limited to, (i) estimates of the Company's reserves of oil, NGL and natural gas, (ii) future cash flows from oil and natural gas properties, (iii) depletion, depreciation and amortization, (iv) asset retirement obligations, (v) stock-based compensation, (vi) deferred income taxes, (vii) fair value of assets acquired and liabilities assumed in an acquisition and (viii) fair values of commodity derivatives, commodity deferred premiums and performance unit awards. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management's best judgment. Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment. Such estimates and assumptions are adjusted when facts and circumstances dictate. Illiquid credit markets and volatile equity and energy markets have combined to increase the uncertainty inherent in such estimates and assumptions. Management believes its estimates and assumptions to be reasonable under the circumstances. As future events and their effects cannot be determined with precision, actual values and results could differ from these estimates. Any changes in estimates resulting from future changes in the economic environment will be reflected in the financial statements in future periods.
c. Reclassifications
Certain amounts in the accompanying consolidated financial statements have been reclassified to conform to the 2015 presentation. These reclassifications had no impact to previously reported net income, stockholders' equity or cash flows. See Notes 7 and 14 for discussion regarding reclassifications related to the Company's early adoption of new guidance related to the classification of income taxes. See Notes 2.k, 5.h and 14 for discussion regarding the Company's early adoption of new guidance related to the presentation of deferred loan costs.
d. Cash and cash equivalents
The Company defines cash and cash equivalents to include cash on hand, cash in bank accounts and highly liquid investments with original maturities of three months or less. The Company maintains cash and cash equivalents in bank deposit accounts and money market funds that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk on such accounts. See Note 11 for discussion regarding the Company's exposure to credit risk.
e. Accounts receivable
The Company sells produced and purchased oil, NGL and natural gas to various customers and participates with other parties in the development and operation of oil and natural gas properties. The Company's accounts receivable are generally unsecured. Accounts receivable for joint interest billings are recorded as amounts billed to customers less an allowance for doubtful accounts.
Joint interest operations amounts are considered past due after 30 days. The Company determines joint interest operations accounts receivable allowances based on management's assessment of the creditworthiness of the joint interest owners. Additionally, as the operator of the majority of its wells, the Company has the ability to realize the receivables through netting of anticipated future production revenues. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging and existing industry and economic data. The Company reviews its allowance for doubtful accounts quarterly. Past due amounts greater than 90 days and over a specified amount are reviewed individually for collectability. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is remote.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Accounts receivable consisted of the following components as of December 31:
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(1)
Accounts receivable for joint operations are presented net of an allowance for doubtful accounts of $0.2 million and $0.8 million as of December 31, 2015 and 2014, respectively.
f. Derivatives
The Company uses derivatives to reduce exposure to fluctuations in the prices of oil and natural gas. By removing a significant portion of the price volatility associated with future production, the Company expects to mitigate, but not eliminate, the potential effects of variability in cash flows from operations due to fluctuations in commodity prices. These transactions are in the form of puts, swaps, collars and basis swaps. In addition, in prior periods the Company entered into interest rate derivatives.
Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing pricing models for substantially similar instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. See Note 9 for discussion regarding the fair value of the Company's derivatives.
The Company's derivatives were not designated as hedges for accounting purposes for any of the periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses on derivatives are included in cash flows from operating activities. See Notes 8 and 9 for discussion regarding the Company's commodity derivatives.
g. Oil and natural gas properties
The Company uses the full cost method of accounting for its oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of finding oil and natural gas are capitalized and amortized on a composite units of production method based on proved oil, NGL and natural gas reserves. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals and other costs related to such activities. Costs, including related employee costs, associated with production and general corporate activities are expensed in the period incurred. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.
The Company computes the provision for depletion of oil and natural gas properties using the units of production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the depletion base until the properties associated with these costs are evaluated. Approximately $140.3 million and $342.7 million of such costs were excluded from the depletion base as of December 31, 2015 and 2014, respectively. The depletion base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. Total accumulated depletion and impairment for oil and natural gas properties was $4.2 billion and $1.6 billion for the years ended December 31, 2015 and 2014, respectively. Depletion expense for oil and natural gas properties was $263.7 million, $237.1 million and $228.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. Depletion per barrel of oil equivalent for the Company's oil and natural gas properties was $16.13, $20.21 and $20.34 for the years ended December 31, 2015, 2014 and 2013, respectively.
The Company excludes the costs directly associated with acquisition and evaluation of unevaluated properties from the depletion calculation until it is determined whether or not proved reserves can be assigned to the properties. The Company capitalizes a portion of its interest costs on its unevaluated properties. Capitalized interest becomes a part of the cost of the unevaluated properties and is subject to depletion when proved reserves can be assigned to the associated properties. All items
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
classified as unevaluated property are assessed on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of evaluated reserves and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion.
The full cost ceiling is based principally on the estimated future net revenues from proved oil and natural gas properties discounted at 10%. Per the Securities and Exchange Commission ("SEC") guidelines, companies are required to use the unweighted arithmetic average first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period before differentials ("Benchmark Prices"). The Benchmark Prices are then adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead ("Realized Prices"). The Realized Prices are utilized to calculate the discounted future net revenues in the full cost ceiling calculation.
In the event the unamortized cost of evaluated oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period such excess occurs. Once incurred, a write-down of oil and natural gas properties is not reversible.
The following table presents the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded as of the periods presented:
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(1)
For periods prior to January 1, 2015, the Company presented reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability of 2015 with prior periods.
Full cost ceiling impairment expense for the year ended December 31, 2015 in the consolidated statements of operations was $2.4 billion. The amount is included in the "Impairment expense" line item in the consolidated statements of operations and in the financial information provided for the Company's exploration and production segment presented in Note 17.
h. Midstream service assets
Midstream service assets consist of oil and natural gas pipeline gathering assets, related equipment, oil delivery stations, water storage and treatment facilities and their related asset retirement cost. The oil and natural gas pipeline gathering assets, related equipment, oil delivery stations and water storage and treatment facilities are recorded at cost, net of impairment. See Note 2.m for discussion regarding midstream service asset retirement cost. Depreciation of assets is recorded using the straight-line method based on estimated useful lives of 10 to 20 years, as applicable. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation expense from continuing operations for midstream service assets was $7.5 million, $4.3 million and $1.5 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Midstream service assets consist of the following as of December 31:
i. Other fixed assets
Other fixed assets are recorded at cost and are subject to depreciation and amortization. Land is recorded at cost and is not subject to depreciation. Depreciation and amortization of other fixed assets is provided using the straight-line method based on estimated useful lives of three to ten years, as applicable. Leasehold improvements are capitalized and amortized over the shorter of the estimated useful lives of the assets or the terms of the related leases. Expenditures for significant betterments or renewals, which extend the useful lives of existing fixed assets, are capitalized and depreciated. Upon retirement or disposition, the cost and related accumulated depreciation and amortization are removed from the accounts and any gain or loss is recognized in "Loss on disposal of assets, net" in the consolidated statements of operations. Depreciation and amortization expense from continuing operations for other fixed assets was $6.5 million, $5.1 million and $4.4 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Other fixed assets consist of the following as of December 31:
j. Long-lived assets, materials and supplies and line-fill
Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets' carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.
Materials and supplies used in developing oil and natural gas properties and midstream service assets are carried at the lower of cost or market ("LCM") and are included in "Other current assets" and "Other assets, net" on the consolidated balance sheets. The market price for materials and supplies is determined utilizing the Company's recent prices paid to acquire materials. During the years ended December 31, 2015 and 2014, the Company reduced materials and supplies by $2.8 million and $1.8 million, respectively, in order to reflect the balance at LCM. These adjustments are included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's exploration and production segment presented in Note 17. The Company determined an LCM adjustment was not necessary for materials and supplies during the year ended December 31, 2013.
The minimum volume of product in a pipeline system that enables the system to operate is known as line-fill, and is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Beginning in the fourth quarter of 2014, the Company owns oil line-fill in third-party pipelines, which is accounted for at LCM with cost determined using the weighted-average cost method, and is included in "Other assets, net" on the consolidated balance sheets. The LCM adjustment is determined utilizing a quoted market price adjusted for regional price differentials (Level 2). For the years ended December 31, 2015 and 2014, the Company recorded LCM adjustments of $1.3 million and $2.1 million, respectively, related to its line-fill, which is included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's midstream and marketing segment presented in Note 17.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
For the year ended December 31, 2015, the Company recorded an impairment, based on an internally developed cash flow model, of $1.3 million related to its compressed natural gas station. This amount is included in "Impairment expense" in the consolidated statements of operations and as "Impairment expense" for the Company's midstream and marketing segment presented in Note 17. There were no comparable impairments recorded for the years ended December 31, 2014 or 2013.
k. Debt issuance costs
Debt issuance fees, which are recorded at cost, net of amortization, are amortized over the life of the respective debt agreements utilizing the effective interest and straight-line methods. The Company capitalized $6.8 million of debt issuance costs during the year ended December 31, 2015 mainly as a result of the issuance of the March 2023 Notes (as defined below). The Company capitalized $7.8 million of debt issuance costs during the year ended December 31, 2014 mainly as a result of the issuance of the January 2022 Notes (as defined below). The Company capitalized $3.0 million of debt issuance costs during the year ended December 31, 2013. The Company had total debt issuance costs of $23.9 million and $28.5 million, net of accumulated amortization of $17.0 million and $19.4 million, as of December 31, 2015 and 2014, respectively.
The Company wrote-off approximately $6.6 million of debt issuance costs during the year ended December 31, 2015 as a result of the early redemption of the January 2019 Notes (as defined below), which is included in the consolidated statements of operations in the "Loss on early redemption of debt" line item. During the year ended December 31, 2014, $0.1 million of debt issuance costs were written-off as a result of changes in the borrowing base of the Senior Secured Credit Facility (as defined below) due to the issuance of the January 2022 Notes. During the year ended December 31, 2013, $1.5 million of debt issuance costs were written off as a result of changes in the borrowing base of the Senior Secured Credit Facility due to the Anadarko Basin Sale (as defined below). Debt issuance costs written-off during the years ended December 31, 2014 and 2013 are included in the consolidated statements of operations in the "Write-off of debt issuance costs" line item. See Notes 4.d, 5.b, 5.c, 5.e and 5.f for definition of and information regarding the Anadarko Basin Sale, March 2023 Notes, January 2022 Notes, January 2019 Notes and Senior Secured Credit Facility, respectively.
During the year ended December 31, 2015, the Company early-adopted new guidance that seeks to simplify the presentation of debt issuance costs and has applied its provisions retrospectively. The adoption of this standard resulted in $18.8 million and $21.8 million of unamortized debt issuance costs related to the Company's senior unsecured notes being presented in "Long-term debt, net" rather than the past presentation in "Other assets, net" within its consolidated balance sheets as of December 31, 2015 and December 31, 2014, respectively. Other than this reclassification of the December 31, 2014 amount, the adoption of this standard did not have an impact on the Company's consolidated financial statements. Debt issuance costs related to the Senior Secured Credit Facility remain presented in "Other assets, net" on the Company's consolidated balance sheets. See Notes 5.h and 14 for additional discussion of debt issuance costs.
Future amortization expense of debt issuance costs as of the period presented is as follows:
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
l. Other current liabilities
Other current liabilities consist of the following components as of December 31:
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(1)
See Notes 15, 16 and 19.b for additional discussion regarding our equity method investee.
m. Asset retirement obligations
Asset retirement obligations associated with the retirement of tangible long-lived assets are recognized as a liability in the period in which they are incurred and become determinable. The associated asset retirement costs are part of the carrying amount of the long-lived asset. Subsequently, the asset retirement cost included in the carrying amount of the related long-lived asset is charged to expense through depletion, or for midstream service asset retirement cost through depreciation, of the associated asset. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as corresponding accretion expense.
The fair value of additions to the asset retirement obligation liability is measured using valuation techniques consistent with the income approach, which converts future cash flows into a single discounted amount. Significant inputs to the valuation include: (i) estimated plug and abandonment cost per well based on Company experience, (ii) estimated remaining life per well, (iii) estimated removal and/or remediation costs for midstream service assets, (iv) estimated remaining life of midstream service assets, (v) future inflation factors and (vi) the Company's average credit adjusted risk-free rate. Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including, in addition to those noted above, the ultimate settlement of these amounts, the ultimate timing of such settlement and changes in legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation liability, a corresponding adjustment will be made to the asset balance.
The Company is obligated by contractual and regulatory requirements to remove certain pipeline and gas gathering assets and perform other remediation of the sites where such pipeline and gas gathering assets are located upon the retirement of those assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates are indeterminate. The Company will record an asset retirement obligation for pipeline and gas gathering assets in the periods in which settlement dates are reasonably determinable.
The following reconciles the Company's asset retirement obligation liability as of December 31:
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(1)
The revision of estimates that occurred during the year ended December 31, 2015 is mainly related to a change in the estimated remaining life per well due to declining commodity prices.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
n. Fair value measurements
The carrying amounts reported in the consolidated balance sheets for cash and cash equivalents, accounts receivable, accounts payable, undistributed revenue and royalties, accrued capital expenditures and other accrued assets and liabilities approximate their fair values. See Note 5.g for fair value disclosures related to the Company's debt obligations. The Company carries its derivatives at fair value. See Note 9 for details regarding the fair value of the Company's derivatives.
o. Treasury stock
Laredo's employees may elect to have the Company withhold shares of stock to satisfy their tax withholding obligations that arise upon the lapse of restrictions on their stock awards. Such treasury stock is recorded at cost and retired upon acquisition.
p. Revenue recognition
Oil, NGL and natural gas revenues are recorded using the sales method. Under this method, the Company recognizes revenues based on actual volumes of oil, NGL and natural gas sold to purchasers. For natural gas sales, the Company and other joint interest owners may sell more or less than their entitlement share of the volumes produced. Under the sales method, when a working interest owner has overproduced in excess of its share of remaining estimated reserves, the overproduced party recognizes the excessive imbalance as a liability. If the underproduced working interest owner determines that an overproduced owner's share of remaining net reserves is insufficient to settle the imbalance, the underproduced owner recognizes a receivable, net of any allowance from the overproduced working interest owner. The Company is also subject to natural gas pipeline imbalances, which are recorded as accounts receivable or payable at values consistent with contractual arrangements with the owner of the pipeline. The Company did not have any producer or pipeline imbalance positions as of December 31, 2015 or 2014. During the year ended December 31, 2013, the majority of the Company's natural gas producer imbalance positions were transferred to a buyer in connection with the Anadarko Basin Sale (defined below). Prior to their disposition, the value of net overproduced positions arising during the year ended December 31, 2013, which increased oil and natural gas sales, was $0.03 million.
Midstream service revenues are recorded at the time products are sold or services are provided to third parties at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable. Revenues and expenses attributable to oil purchases and sales are reported on a gross basis when the Company takes title to the products and has risks and rewards of ownership.
q. Fees received for the operation of jointly-owned oil and natural gas properties
The Company receives fees for the operation of jointly-owned oil and natural gas properties and records such reimbursements as a reduction of general and administrative expenses.
The following amounts have been recorded for the periods presented:
r. Compensation awards
Stock-based compensation expense, net of amounts capitalized, is included in "General and administrative" in the Company's consolidated statements of operations over the awards' vesting periods and is based on the awards' grant date fair value. The Company utilizes the closing stock price on the grant date, less an expected forfeiture rate, to determine the fair value of service vesting restricted stock awards and a Black-Scholes pricing model to determine the fair values of service vesting restricted stock option awards. The Company utilizes a Monte Carlo simulation prepared by an independent third party to determine the fair values of the performance share awards and performance unit awards. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of its oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets. See Note 6 for further discussion regarding the restricted stock awards, restricted stock option awards, performance share awards and performance unit awards.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
s. Income taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is determined it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. See Note 7 for detail of amounts recorded in the consolidated financial statements and discussion regarding the valuation allowance taken in 2015.
The Company evaluates uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, the Company determines whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more-likely-than-not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. The Company has no unrecognized tax benefits related to uncertain tax positions in the consolidated financial statements at December 31, 2015, 2014 or 2013.
t. Environmental
The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, among other things, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed in the period incurred. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment or remediation is probable and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. Management believes no materially significant liabilities of this nature existed as of December 31, 2015 or 2014.
u. Supplemental disclosures of cash flow and non-cash investing and financing information
The following table summarizes the supplemental disclosure of cash flow information for the periods presented:
The following presents the supplemental disclosure of non-cash investing and financing information for the periods presented:
Note 3-Equity offerings
a. March 2015 Equity Offering
On March 5, 2015, the Company completed the sale of 69,000,000 shares of Laredo's common stock at a price to the public of $11.05 per share (the "March 2015 Equity Offering"). The Company received net proceeds of $754.2 million, after underwriting discounts and commissions and offering expenses, from the March 2015 Equity Offering. Entities affiliated with Warburg Pincus LLC ("Warburg Pincus") purchased 29,800,000 shares in the March 2015 Equity Offering, following which
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Warburg Pincus owned 41.0% of Laredo's common stock. There were no comparative offerings of the Company's stock during the year ended December 31, 2014.
b. August 2013 Equity Offering
On August 19, 2013, Laredo, together with certain affiliates of Warburg Pincus and members of the Company's management (together with Warburg Pincus, the "Selling Stockholders") completed the sale of (i) 13,000,000 shares of Laredo's common stock by Laredo and (ii) 3,000,000 shares of Laredo's common stock by the Selling Stockholders, at a price to the public of $23.75 per share ($22.9781 per share, net of underwriting discounts) (the "August 2013 Equity Offering"). On August 27, 2013, certain of the Selling Stockholders sold an additional 1,577,583 shares of Laredo's common stock pursuant to the option to purchase additional shares of Laredo's common stock granted to the associated underwriters. The Company received net proceeds of $298.1 million, after underwriting discounts and commissions and offering expenses, from the August 2013 Equity Offering. The Company did not receive any proceeds from either of the sales of shares of Laredo's common stock by the Selling Stockholders.
Note 4-Acquisitions and divestitures
a. 2015 Divestiture of non-strategic assets
On September 15, 2015, the Company completed the sale of non-strategic and primarily non-operated properties and associated production totaling 6,060 net acres and 123 producing properties in the Midland Basin to a third-party buyer for a purchase price of $65.5 million. After transaction costs reflecting an economic effective date of July 1, 2015, the net proceeds were $64.8 million, net of working capital adjustments and post-closing adjustments. The purchase price, excluding post-closing adjustments, was allocated to oil and natural gas properties pursuant to the rules governing full cost accounting.
Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company has no continuing involvement in the properties. This divestiture does not represent a strategic shift and will not have a major effect on the Company's operations or financial results.
The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented:
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(1)
Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.
b. Summary of 2014 and 2013 acquisitions
The Company accounts for acquisitions of evaluated and unevaluated oil and natural gas properties under the acquisition method of accounting. Accordingly, the Company conducts assessments of net assets acquired and recognizes amounts for identifiable assets acquired and liabilities assumed at the estimated acquisition date fair values, while transaction and integration costs associated with the acquisitions are expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. The most significant assumptions relate to the estimated fair values of evaluated and unevaluated oil and natural gas properties. The fair value of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted-average cost of capital rate. The market-based weighted-average cost of capital rate is subjected to additional project-specific risk factors. To compensate for the inherent risk of estimating the value of the unevaluated properties, the discounted future net revenues of probable and possible reserves are reduced by additional risk-weighting factors.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The following table presents the Company's 2014 and 2013 acquisitions. For further discussion of the estimates of fair value of the acquired assets and liabilities of these acquisitions, see Note C in the Company's 2013 Annual Report on Form 10-K and Note 3 in the Company's 2014 Annual Report on Form 10-K.
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(1)
The fair value of the acquired assets and liabilities were allocated in the following manner: $9.7 million to evaluated properties, $27.1 million to unevaluated properties, $0.2 million to other assets and $0.2 million to other liabilities.
(2)
In accordance with the acquisition agreement, on September 6, 2013, Laredo issued 123,803 restricted shares of its common stock to the sellers (the "Acquisition Shares"). In accordance with federal securities laws, the Acquisition Shares were restricted from trading on public markets for six months from the acquisition date. For accounting purposes, the fair value of the Acquisition Shares was determined in accordance with GAAP by adjusting the closing price of $26.21 per share of Laredo's common stock on September 6, 2013 for a discount for lack of marketability. The discount of 6.64% was determined utilizing an Asian put option model, which includes an assumption of the estimated volatility of Laredo's common stock. This assumption represents a Level 3 input under the fair value hierarchy, as described in Note 9.
c. 2013 divestiture of Dalhart Basin acreage
On December 20, 2013, the Company completed the sale of 37,000 net acres and one producing property in the Dalhart Basin for $20.4 million, subject to customary closing adjustments.
d. 2013 divestiture of Anadarko assets
On August 1, 2013, the Company completed the sale of its oil and natural gas properties, associated pipeline assets and various other associated property and equipment in the Anadarko Granite Wash, Central Texas Panhandle and the Eastern Anadarko Basin (the "Anadarko Basin Sale") to certain affiliates of EnerVest, Ltd. (collectively, "EnerVest") and certain other third parties in connection with the exercise of such third parties' preferential rights associated with the oil and gas assets. The purchase price consisted of $400.0 million from EnerVest and $38.0 million from the third parties. Approximately $388.0 million of the purchase price, excluding closing adjustments, was allocated to oil and natural gas properties pursuant to to the rules governing full cost accounting. After transaction costs and adjustments at closing reflecting an economic effective date of April 1, 2013, the net proceeds were $428.3 million, net of working capital adjustments.
Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Company and the Company does not have continuing involvement in the operations of these properties. The results of operations of the oil and natural gas properties that are a component of the Anadarko Basin Sale are not presented as discontinued operations pursuant to the rules governing full cost accounting for oil and natural gas properties.
The following table presents revenues and expenses of the oil and natural gas properties that are a component of the Anadarko Basin Sale included in the accompanying consolidated statements of operations for the period presented:
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(1)
Expenses include (i) lease operating expense, (ii) production and ad valorem tax expense, (iii) accretion expense and (iv) depletion expense.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The results of operations of the associated pipeline assets and various other associated property and equipment ("Pipeline Assets") are presented as results of discontinued operations, net of tax in these consolidated financial statements. Accordingly, the Company has reclassified the financial results and the related notes for all prior periods presented to reflect these operations as discontinued. As a result of the sale of the Pipeline Assets, a gain of $3.2 million was recognized in the consolidated statements of operations in the line item "Loss on disposal of assets, net" during the year ended December 31, 2013.
The following represents operating results from discontinued operations for the period presented:
Note 5-Debt
a. Interest expense
The following amounts have been incurred and charged to interest expense for the periods presented:
b. March 2023 Notes
On March 18, 2015, the Company completed an offering of $350.0 million in aggregate principal amount of 6 1/4% senior unsecured notes due 2023 (the "March 2023 Notes"), and entered into an Indenture (the "Base Indenture"), as supplemented by the Supplemental Indenture (the "Supplemental Indenture" and, together with the Base Indenture, the "Indenture"), among Laredo, LMS and GCM, as guarantors, and Wells Fargo Bank, National Association, as trustee. The March 2023 Notes will mature on March 15, 2023 with interest accruing at a rate of 6 1/4% per annum and payable semi-annually in cash in arrears on March 15 and September 15 of each year, commencing September 15, 2015. The March 2023 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain automatic customary releases, including the sale, disposition, or transfer of all of the capital stock or of all or substantially all of the assets of a subsidiary guarantor to one or more persons that are not the Company or a restricted subsidiary, exercise of legal defeasance or covenant defeasance options or satisfaction and discharge of the Indenture, designation of a subsidiary guarantor as a non-guarantor restricted subsidiary or as an unrestricted subsidiary in accordance with the Indenture, release from guarantee under the Senior Secured Credit Facility (as defined below), or liquidation or dissolution (collectively, the "Releases").
The March 2023 Notes were offered and sold pursuant to a prospectus supplement dated March 4, 2015 and the base prospectus dated March 22, 2013, relating to the Company's effective shelf registration statement on Form S-3 (File No. 333-187479). The Company received net proceeds of $343.6 million from the offering, after deducting the underwriters'
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
discount and the estimated outstanding offering expenses. In April 2015, the Company used the proceeds of the offering to fund a portion of the Company's redemption of the January 2019 Notes (as defined below). See Note 5.e for additional discussion of this early redemption.
The Company may redeem, at its option, all or part of the March 2023 Notes at any time on or after March 15, 2018, at the applicable redemption price plus accrued and unpaid interest to, but not including, the date of redemption. Further, before March 15, 2018, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the March 2023 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 106.25% of the principal amount of the March 2023 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the March 2023 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering. If a change of control occurs prior to March 15, 2016, the Company may redeem all, but not less than all, of the March 2023 Notes at a redemption price equal to 110% of the principal amount of the March 2023 Notes plus any accrued and unpaid interest to, but not including, the date of redemption.
c. January 2022 Notes
On January 23, 2014, the Company completed an offering of $450.0 million in aggregate principal amount of 5 5/8% senior unsecured notes due 2022 (the "January 2022 Notes"), and entered into an Indenture (the "2014 Indenture") among Laredo, LMS as guarantor and Wells Fargo Bank, National Association, as trustee. The January 2022 Notes will mature on January 15, 2022 with interest accruing at a rate of 5 5/8% per annum and payable semi-annually in cash in arrears on January 15 and July 15 of each year, commencing July 15, 2014. The January 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases.
The January 2022 Notes were issued pursuant to the 2014 Indenture in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act"). The January 2022 Notes were offered and sold only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S under the Securities Act. The Company received net proceeds of $442.2 million from the offering, after deducting the initial purchasers' discount and the estimated outstanding offering expenses. The Company used the net proceeds of the offering for general working capital purposes.
Laredo will have the option to redeem all or part of the January 2022 Notes at any time on and after January 15, 2017, at the applicable redemption price plus accrued and unpaid interest to the date of redemption. In addition, the Company may redeem, at its option, all or part of the January 2022 Notes at any time prior to January 15, 2017 at a redemption price equal to 100% of the principal amount of the January 2022 Notes redeemed plus the applicable premium and accrued and unpaid interest and additional interest, if any, to the date of redemption. Further, before January 15, 2017, the Company may on one or more occasions redeem up to 35% of the aggregate principal amount of the January 2022 Notes in an amount not exceeding the net proceeds from one or more private or public equity offerings at a redemption price of 105.625% of the principal amount of the January 2022 Notes, plus accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the January 2022 Notes remains outstanding immediately after such redemption and the redemption occurs within 180 days of the closing date of each such equity offering.
d. May 2022 Notes
On April 27, 2012, the Company completed an offering of $500.0 million in aggregate principal amount of 7 3/8% senior unsecured notes due 2022 (the "May 2022 Notes"). The May 2022 Notes will mature on May 1, 2022 and bear an interest rate of 7 3/8% per annum, payable semi-annually, in cash in arrears on May 1 and November 1 of each year, commencing November 1, 2012. The May 2022 Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases.
The May 2022 Notes were issued under, and are governed by, an indenture and supplement thereto, each dated April 27, 2012 (collectively, and as further supplemented, the "2012 Indenture"), among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and the guarantors named therein. The 2012 Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of dividends or similar restricted payments, entering into transactions with affiliates and limitations on asset sales. Indebtedness under the May 2022 Notes may be accelerated in certain circumstances upon an event of default as set forth in the 2012 Indenture.
Laredo will have the option to redeem the May 2022 Notes, in whole or in part, at any time on or after May 1, 2017, at the redemption prices (expressed as percentages of principal amount) of 103.688% for the 12-month period beginning on May 1, 2017, 102.458% for the 12-month period beginning on May 1, 2018, 101.229% for the 12-month period beginning on May 1, 2019 and 100.000% beginning on May 1, 2020 and at any time thereafter, together with any accrued and unpaid interest, if any,
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
to the date of redemption. In addition, before May 1, 2017, Laredo may redeem all or any part of the May 2022 Notes at a redemption price equal to the sum of the principal amount thereof, plus a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. Laredo may also be required to make an offer to purchase the May 2022 Notes upon a change of control triggering event.
e. January 2019 Notes
On January 20, 2011, the Company completed an offering of $350.0 million 9 1/2% senior unsecured notes due 2019 (the "January Notes") and on October 19, 2011, the Company completed an offering of an additional $200.0 million 9 1/2% senior unsecured notes due 2019 (the "October Notes" and together with the January Notes, the "January 2019 Notes"). The January 2019 Notes were due to mature on February 15, 2019 and bore an interest rate of 9 1/2% per annum, payable semi-annually, in cash in arrears on February 15 and August 15 of each year. The January 2019 Notes were fully and unconditionally guaranteed on a senior unsecured basis by the Guarantors and certain of the Company's future restricted subsidiaries, subject to certain Releases.
The January 2019 Notes were issued under and were governed by an indenture dated January 20, 2011 (as supplemented, the "2011 Indenture") among Laredo Inc, Wells Fargo Bank, National Association, as trustee, and guarantors named therein. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of or similar restricted payments, the undertaking of transactions with Laredo's unrestricted affiliates and limitations on asset sales.
On April 6, 2015 (the "Redemption Date"), utilizing a portion of the proceeds from the March 2015 Equity Offering and the March 2023 Notes offering, the entire $550.0 million outstanding principal amount of the January 2019 Notes was redeemed at a redemption price of 104.750% of the principal amount of the January 2019 Notes, plus accrued and unpaid interest up to the Redemption Date. The Company recognized a loss on extinguishment of $31.5 million related to the difference between the redemption price and the net carrying amount of the extinguished January 2019 Notes.
f. Senior Secured Credit Facility
As of December 31, 2015, the Fourth Amended and Restated Credit Agreement (as amended, the "Senior Secured Credit Facility"), which matures November 4, 2018, had a maximum credit amount of $2.0 billion, a borrowing base of $1.15 billion and an aggregate elected commitment of $1.0 billion with $135.0 million outstanding and was subject to an interest rate of 1.90%. The borrowing base is subject to a semi-annual redetermination occurring each May 1 and November 1 based on the financial institutions' evaluation of the Company's oil and natural gas reserves. As defined in the Senior Secured Credit Facility, (i) the Adjusted Base Rate advances under the facility bear interest payable quarterly at an Adjusted Base Rate plus applicable margin, which ranges from 0.5% to 1.5% and (ii) the Eurodollar advances under the facility bear interest, at the Company's election, at the end of one-month, two-month, three-month, six-month or, to the extent available, 12-month interest periods (and in the case of six-month and 12-month interest periods, every three months prior to the end of such interest period) at an Adjusted London Interbank Offered Rate plus an applicable margin, which ranges from 1.5% to 2.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility. Laredo is also required to pay an annual commitment fee on the unused portion of the financial institutions' commitment of 0.375% to 0.5%, based on the ratio of outstanding revolving credit to the total commitment under the Senior Secured Credit Facility.
The Senior Secured Credit Facility is secured by a first-priority lien on Laredo and the Guarantor's assets and stock, including oil, NGL and natural gas properties, constituting at least 80% of the present value of the Company's evaluated reserves. Further, the Company is subject to various financial and non-financial ratios on a consolidated basis, including a current ratio at the end of each calendar quarter, of not less than 1.00 to 1.00. As defined by the Senior Secured Credit Facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available capacity and exclusive of current balances associated with derivative positions. Additionally, at the end of each calendar quarter, the Company must maintain a ratio of (I) its consolidated net income (a) plus each of the following; (i) any provision for (or less any benefit from) income or franchise taxes; (ii) consolidated net interest expense; (iii) depletion, depreciation and amortization expense; (iv) exploration expenses; and (v) other non-cash charges, and (b) minus all non-cash income ("EBITDAX"), as defined in the Senior Secured Credit Facility, to (II) the sum of net interest expense plus letter of credit fees of not less than 2.50 to 1.00, in each case for the four quarters then ending. The Senior Secured Credit Facility contains both financial and non-financial covenants and the Company was in compliance with these covenants for all periods presented.
Additionally, the Senior Secured Credit Facility provides for the issuance of letters of credit, limited to the lesser of total capacity or $20.0 million. No letters of credit were outstanding as of December 31, 2015 or 2014.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
g. Fair value of debt
The Company has not elected to account for its debt at fair value. The following table presents the carrying amounts and fair values of the Company's debt as of the periods presented:
_____________________________________________________________________________
(1)
The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.
The fair values of the debt outstanding on the January 2019 Notes, the January 2022 Notes, the May 2022 Notes and the March 2023 Notes were determined using the December 31, 2015 and 2014 quoted market price (Level 1) for each respective instrument. The fair values of the outstanding debt on the Senior Secured Credit Facility as of December 31, 2015 and 2014 were estimated utilizing pricing models for similar instruments (Level 2). See Note 9 for information about fair value hierarchy levels.
h. Debt issuance costs
The following tables summarize the net presentation of the Company's long-term debt and debt issuance cost on the consolidated balance sheets as of the periods presented:
_____________________________________________________________________________
(1)
The long-term debt amount includes the October Notes' unamortized bond premium of $1.3 million as of December 31, 2014.
(2)
Debt issuance costs related to our Senior Secured Credit Facility are recorded in "Other assets, net" on the consolidated balance sheets.
Note 6-Employee compensation
The Company has a Long-Term Incentive Plan (the "LTIP"), which provides for the granting of incentive awards in the form of restricted stock awards, restricted stock option awards, performance share awards, performance unit awards and other awards. The LTIP provides for the issuance of 10.0 million shares.
The Company recognizes the fair value of stock-based compensation awards expected to vest over the requisite service period as a charge against earnings, net of amounts capitalized. The Company's stock-based compensation awards are accounted for as equity instruments and its performance unit awards are accounted for as liability awards. Stock-based compensation is included in "General and administrative" in the consolidated statements of operations. On January 1, 2014, the Company began capitalizing a portion of stock-based compensation for employees who are directly involved in the acquisition, exploration and development of oil and natural gas properties into the full cost pool. Capitalized stock-based compensation is included as an addition to "Oil and natural gas properties" in the consolidated balance sheets.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
a. Restricted stock awards
All restricted stock awards are treated as issued and outstanding in the accompanying consolidated financial statements. Per the award agreement terms, if an employee terminates employment prior to the restriction lapse date, for reasons other than death and disability, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. If the employee's termination of employment is by reason of death or disability, all of the holder's restricted stock will automatically vest. Restricted stock awards granted to officers and employees vest in a variety of vesting schedules including (i) 20% at the grant date and then 20% annually thereafter, (ii) 33%, 33% and 34% per year beginning on the first anniversary date of the grant, (iii) 50% in year two and 50% in year three, (iv) fully on the first anniversary of the grant date and (v) fully on the third anniversary of the grant date. Restricted stock awards granted to non-employee directors vest fully on the first anniversary of the grant date.
The following table reflects the outstanding restricted stock awards for the years ended December 31, 2015, 2014 and 2013:
_____________________________________________________________________________
(1)
The vesting of certain restricted stock awards could result in federal and state income tax expense or benefit related to the difference between the market price of the common stock at the date of vesting and the date of grant. See Note 7 for additional discussion regarding the tax impact of vested restricted stock awards.
The Company utilizes the closing stock price on the grant date to determine the fair value of service vesting restricted stock awards. As of December 31, 2015, unrecognized stock-based compensation related to the restricted stock awards expected to vest was $21.6 million. Such cost is expected to be recognized over a weighted-average period of 1.74 years.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
b. Restricted stock option awards
Restricted stock option awards granted under the LTIP vest and are exercisable in four equal installments on each of the four anniversaries of the grant date. The following table reflects the stock option award activity for the years ended December 31, 2015, 2014 and 2013:
_____________________________________________________________________________
(1)
The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option award at the date of grant and the intrinsic value of the stock option award when exercised. See Note 7 for additional discussion regarding the tax impact of exercised stock option awards.
(2)
The vested and exercisable options as of December 31, 2015 had no aggregate intrinsic value.
(3)
The restricted stock options expected to vest as of December 31, 2015 had no aggregate intrinsic value.
The Company utilizes the Black-Scholes option pricing model to determine the fair value of restricted stock option awards and is recognizing the associated expense on a straight-line basis over the four-year requisite service period of the awards. Determining the fair value of equity-based awards requires judgment, including estimating the expected term that stock option awards will be outstanding prior to exercise and the associated volatility. As of December 31, 2015, unrecognized stock-based compensation related to restricted stock option awards expected to vest was $7.0 million. Such cost is expected to be recognized over a weighted-average period of 2.35 years.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The assumptions used to estimate the fair value of restricted stock options granted are as follows:
_____________________________________________________________________________
(1)
U.S. Treasury yields as of the grant date were utilized for the risk-free interest rate assumption, correlating the treasury yield terms to the expected life of the option.
(2)
As the Company had limited or no exercise history at the time of valuation relating to terminations and modifications, expected option life assumptions were developed using the simplified method in accordance with GAAP.
(3)
The Company utilized its own volatility in order to develop the expected volatility for the February 27, 2015 grant. The prior grants utilized a peer historical look-back, which was weighted with the Company's own volatility, in order to develop the expected volatility.
In accordance with the LTIP and stock option agreement, the options granted will become exercisable in accordance with the following schedule based upon the number of full years of the optionee's continuous employment or service with the Company, following the date of grant:
No shares of common stock may be purchased unless the optionee has remained in continuous employment with the Company for one year from the grant date. Unless terminated sooner, the option will expire if and to the extent it is not exercised within 10 years from the grant date. The unvested portion of a stock option award shall expire upon termination of employment, and the vested portion of a stock option award shall remain exercisable for (i) one year following termination of employment by reason of the holder's death or disability, but not later than the expiration of the option period, or (ii) 90 days following termination of employment for any reason other than the holder's death or disability, and other than the holder's termination of employment for cause. Both the unvested and the vested but unexercised portion of a stock option award shall expire upon the termination of the option holder's employment or service by the Company for cause.
c. Performance share awards
The performance share awards granted to management on February 27, 2015 (the "2015 Performance Share Awards") and on February 27, 2014 (the "2014 Performance Share Awards") are subject to a combination of market and service vesting criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the grant date fair value of these awards. The Company has determined these awards are equity awards and recognizes the associated expense on a straight-line basis over the three-year requisite service period of the awards. These awards will be settled, if at all, in stock at the end of the requisite service period based on the achievement of certain performance criteria.
The 2015 Performance Share Awards have a performance period of January 1, 2015 to December 31, 2017 and any shares earned under such awards are expected to be issued in the first quarter of 2018 if the performance criteria are met. During the year ended December 31, 2015, the Company granted 602,501 2015 Performance Share Awards and all remain outstanding as of December 31, 2015. The 271,667 outstanding 2014 Performance Share Awards have a performance period of January 1, 2014 to December 31, 2016 and any shares earned under such awards are expected to be issued in the first quarter of 2017 if the performance criteria are met. No 2014 Performance Share Awards were forfeited during the years ended December 31, 2015 or 2014.
As of December 31, 2015, unrecognized stock-based compensation related to the 2015 Performance Share Awards and the 2014 Performance Share Awards was $9.9 million. Such cost is expected to be recognized over a weighted-average period of 1.86 years.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The assumptions used to estimate the fair value of the Performance Share Awards granted are as follows:
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(1)
The risk-free rate was derived using a zero-coupon yield derived from the Treasury Constant Maturities yield curve on the grant date.
(2)
The Company utilized a peer historical look-back, weighted with the Company's own volatility, to develop the expected volatility.
d. Stock-based compensation award expense
The following has been recorded to stock-based compensation expense for the periods presented:
During the year ended December 31, 2013, two officers' and 20 employees' restricted stock awards and restricted option awards were modified to vest upon the officers' or the employees' retirement or in connection with the employees' termination of employment as a result of the Anadarko Basin Sale. The incremental compensation cost resulting from these modifications recognized during the year ended December 31, 2013 was $4.7 million.
e. Performance unit awards
The performance unit awards issued to management on February 15, 2013 (the "2013 Performance Unit Awards") and on February 3, 2012 (the "2012 Performance Unit Awards") were subject to a combination of market and service vesting criteria. These awards were accounted for as liability awards as they were settled in cash at the end of the requisite service period based on the achievement of certain performance criteria. A Monte Carlo simulation prepared by an independent third party was utilized to determine the fair values of these awards at the grant date and to re-measure the fair values at the end of each reporting period until settlement in accordance with GAAP. The volatility criteria utilized in the Monte Carlo simulation was based on the volatility of the Company's stock price and the stock price volatilities of a group of peer companies defined in each respective award agreement. The liability and related compensation expense of these awards for each period was recognized by dividing the fair value of the total liability by the requisite service period and recording the pro rata share for the period for which service had already been provided.
The 2013 Performance Unit Awards had a performance period of January 1, 2013 to December 31, 2015 and, as their performance criteria were satisfied, they were paid at $143.75 per unit during the first quarter of 2016. The 2012 Performance Unit Awards had a performance period of January 1, 2012 to December 31, 2014 and, as their performance criteria were satisfied, they were paid at $100 per unit during the first quarter of 2015.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The following table reflects the outstanding performance unit awards for the periods presented:
_____________________________________________________________________________
(1)
During the year ended December 31, 2013, certain officers' performance unit awards were modified to vest upon the officers' retirement in 2013. The cash payments for these performance unit awards were paid at $100.00 per unit.
(2)
The 2013 Performance Unit Awards' performance period ended December 31, 2015. Their market and service criteria were met and accordingly they were paid at $143.75 per unit in the first quarter of 2016.
(3)
The 2012 Performance Unit Awards' performance period ended December 31, 2014. Their market and service criteria were met and accordingly they were paid at $100.00 per unit in the first quarter of 2015.
The liability related to the 2013 Performance Unit Awards as of December 31, 2015 was $6.4 million and represents the cash payment made in the first quarter of 2016. The fair value of the 2013 Performance Unit Awards as of December 31, 2014 was $3.5 million. The liability related to the 2012 Performance Unit Awards as of December 31, 2014 was $2.7 million and represents the cash payment made in the first quarter of 2015. The fair values of the 2013 Performance Unit Awards and 2012 Performance Unit Awards as of December 31, 2013 were $5.7 million and $3.8 million, respectively.
The following has been recorded to performance unit award compensation expense for the periods presented:
Compensation expense for the 2012 Performance Unit Awards and the 2013 Performance Unit Awards is recognized in "General and administrative" in the Company's consolidated statements of operations, and the corresponding liabilities are included in "Other current liabilities" and "Other noncurrent liabilities" on the consolidated balance sheets.
f. Defined contribution plan
The Company sponsors a 401(k) defined contribution plan for the benefit of substantially all employees at the date of hire. The plan allows eligible employees to make pre-tax and after-tax contributions up to 100% of their annual compensation, not to exceed annual limits established by the federal government. The Company makes matching contributions of up to 6% of an employee's compensation and may make additional discretionary contributions for eligible employees. Employees are 100% vested in the employer contributions upon receipt.
The following table presents the cost recognized for the Company's defined contribution plan for the periods presented:
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Note 7-Income taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating losses and tax credit carry-forwards. Under this method, deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income (loss) in the period that includes the enactment date.
The Company is subject to federal and state income taxes and the Texas franchise tax. Income tax benefit (expense) attributable to income (loss) from continuing operations for the periods presented consisted of the following:
The following presents the comprehensive benefit (expense) for income taxes for the periods presented:
Income tax benefit (expense) attributable to income (loss) from continuing operations before income taxes differed from amounts computed by applying the applicable federal income tax rate of 35% for the years ended December 31, 2015 and 2014 and 34% for the year ended December 31, 2013 to pre-tax earnings as a result of the following:
The effective tax rate for the Company's continuing operations was 7%, 38% and 39% for the years ended December 31, 2015, 2014 and 2013, respectively. The Company's effective tax rate is affected by changes in valuation allowances, recurring permanent differences and by discrete items that may occur in any given year, but are not consistent from year to year.
A valuation allowance is established to reduce deferred tax assets if it is determined that it is more likely than not that the related tax benefit will not be realized. On a quarterly basis, management evaluates the need for and adequacy of valuation allowances based on the expected realizability of the deferred tax assets and adjusts the amount of such allowances, if necessary. During 2015, in evaluating whether it was more likely than not that the Company’s net deferred tax assets were realized through future net income, management considered all available positive and negative evidence, including (i) its earnings history, (ii) its ability to recover net operating loss carry-forwards, (iii) the existence of significant proved oil and natural gas reserves, (iv) its ability to use tax planning strategies, (v) its current price protection utilizing oil and natural gas
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
hedges, (vi) its future revenue and operating cost projections and (vii) the current market prices for oil and natural gas. Based on all the evidence available, during the year ended December 31, 2015, management determined it was more likely than not that the net deferred tax assets were not realizable, therefore a valuation allowance of $676.0 million was recorded.
The impact of significant discrete items is separately recognized in the year in which the discrete items occur. The vesting of certain restricted stock awards could result in federal and state income tax expense or benefits related to the difference between the market price of the common stock at the date of vesting and the grant date. The exercise of stock option awards could result in federal and state income tax expense or benefits related to the difference between the fair value of the stock option at the grant date and the intrinsic value of the stock option when exercised. The tax impact resulting from vestings of restricted stock awards and exercise of option awards are discrete items. During the years ended December 31, 2015, 2014 and 2013, certain shares related to restricted stock awards vested at times when the Company's stock price was lower than the fair value of those shares at the time of grant. As a result, the income tax deduction related to such shares is less than the expense previously recognized for book purposes. During the years ended December 31, 2014 and 2013, certain restricted stock options were exercised. There were no comparable exercise of stock options during the year ended December 31, 2015. The income tax deduction related to the intrinsic value of the options was less than the expense previously recognized for book purposes. In accordance with GAAP, such shortfalls reduce additional paid-in capital to the extent windfall tax benefits have been previously recognized. However, the Company has not previously recognized any windfall tax benefits. Therefore, such shortfalls are included in income tax benefit (expense) attributable to continuing operations.
The following table presents the tax impact of these shortfalls for the periods presented:
Significant components of the Company's net deferred tax liability as of December 31 are as follows:
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Deferred tax assets and liabilities were classified in the consolidated balance sheets as of December 31 are as follows:
_____________________________________________________________________________
(1)
See Note 14 for discussion regarding the new guidance early adopted by the Company that resulted in a balance sheet reclassification of the deferred tax liability from current to noncurrent for the year ended December 31, 2014.
The following presents the Company's federal net operating loss carry-forwards and their applicable expiration dates as of the period presented:
The Company had federal net operating loss carry-forwards totaling $1.4 billion and state of Oklahoma net operating loss carry-forwards totaling $40.9 million as of December 31, 2015. These carry-forwards begin expiring in 2026. As of December 31, 2015, the Company believes a portion of the net operating loss carry-forwards are not fully realizable. The Company considered all available evidence, both positive and negative, in determining whether, based on the weight of that evidence, a valuation allowance was needed. Such consideration included projected future cash flows from its oil and natural gas reserves (including the timing of those cash flows), the reversal of deferred tax liabilities recorded as of December 31, 2015, the Company's ability to capitalize intangible drilling costs, rather than expensing these costs in order to prevent an operating loss carry-forward from expiring unused, and future projections of Oklahoma sourced income.
The Company's federal and state operating loss carry-forwards include windfall tax deductions from vestings of certain restricted stock awards and stock option exercises that were not recorded in the Company's income tax provision. The amount of windfall tax benefit recognized in additional paid-in capital is limited to the amount of benefit realized currently in income taxes payable. As of December 31, 2015, the Company had suspended additional paid-in capital credits of $4.5 million related to windfall tax deductions. Upon realization of the net operating loss carry-forwards from such windfall tax deductions, the Company would record a benefit of up to $4.5 million in additional paid-in capital.
The Company maintains a valuation allowance to reduce certain deferred tax assets to amounts that are more likely than not to be realized. As of December 31, 2015, a valuation allowance of $677.3 million has been recorded against the deferred tax asset.
Prior to the Internal Consolidation, the Company and its subsidiaries filed a federal corporate income tax return on a consolidated basis. Following the Internal Consolidation, the surviving entities file a single return. The Company's income tax returns for the years 2012 through 2015 remain open and subject to examination by federal tax authorities and/or the tax authorities in Oklahoma and Texas, which are the jurisdictions where the Company has or had operations. Additionally, the statute of limitations for examination of federal net operating loss carry-forwards typically does not begin to run until the year the attribute is utilized in a tax return.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Note 8-Derivatives
a. Commodity derivatives
The Company engages in derivative transactions such as puts, swaps, collars and basis swaps to hedge price risks due to unfavorable changes in oil and natural gas prices related to its production. As of December 31, 2015, the Company had 18 open derivative contracts with financial institutions that extend from January 2016 to December 2017. None of these contracts were designated as hedges for accounting purposes. The contracts are recorded at fair value on the consolidated balance sheets and gains and losses are recognized in current period earnings. Gains and losses on derivatives are reported on the consolidated statements of operations in the "Gain (loss) on derivatives" line items.
Each put transaction has an established floor price. The Company pays the counterparty a premium, which can be deferred until settlement, to enter into the put transaction. When the settlement price is below the floor price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires.
Each swap transaction has an established fixed price. When the settlement price is below the fixed price, the counterparty pays the Company an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, the Company pays its counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume.
Each collar transaction has an established price floor and ceiling. When the settlement price is below the price floor established by these collars, the Company receives an amount from its counterparty equal to the difference between the settlement price and the price floor multiplied by the hedged contract volume. When the settlement price is above the price ceiling established by these collars, the Company pays its counterparty an amount equal to the difference between the settlement price and the price ceiling multiplied by the hedged contract volume.
Each basis swap transaction has an established fixed basis differential corresponding to two index prices. Depending on the difference of the two index prices in relationship to the fixed basis differential, the Company either receives an amount from its counterparty, or pays an amount to its counterparty, equal to the difference multiplied by the hedged contract volume.
During the first quarter of 2014, the Company unwound a physical commodity contract and the associated oil basis swap financial derivative contract that hedged the differential between the Light Louisiana Sweet Argus and the Brent International Petroleum Exchange index oil prices. Prior to its unwind, the physical commodity contract qualified to be scoped out of mark-to-market accounting in accordance with the normal purchase and normal sale scope exemption. Once modified to settle financially in the unwind agreement, the contract ceased to qualify for the normal purchase and normal sale scope exemption, therefore requiring it to be marked-to-market. The Company received net proceeds of $76.7 million from the early termination of these contracts. The Company agreed to settle the contracts early due to the counterparty's decision to exit the physical commodity trading business.
During the year ended December 31, 2013, the following commodity derivative contracts were transferred to a buyer in connection with the Anadarko Basin Sale:
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The following commodity derivative contracts were unwound in connection with the Anadarko Basin Sale during the year ended December 31, 2013:
The following represents cash settlements received (paid) for matured derivatives and for early terminations and modifications of derivatives for the periods presented:
_____________________________________________________________________________
(1)
During the year ended December 31, 2013, the Company received $6.0 million, net of $2.2 million in deferred premiums in settlements from early terminations and modification of commodity derivative contracts.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The following table summarizes open positions as of December 31, 2015, and represents, as of such date, derivatives in place through December 2017 on annual production volumes:
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(1)
Oil derivatives are settled based on the average of the daily settlement prices for the First Nearby Month of the West Texas Intermediate NYMEX Light Sweet Crude Oil Futures Contract for each NYMEX Trading Day during each month ("WTI NYMEX").
(2)
Natural gas derivatives are settled based on the Inside FERC index price for West Texas Waha for the calculation period.
b. Interest rate derivatives
The Company is exposed to market risk for changes in interest rates related to any drawn amount on its Senior Secured Credit Facility. In prior periods, interest rate derivative agreements were used to manage a portion of the exposure related to changing interest rates by converting floating-rate debt to fixed-rate debt. If the London Interbank Offered Rate ("LIBOR") was lower than the fixed rate in the contract, the Company was required to pay the counterparties the difference, and conversely, the counterparties were required to pay the Company if LIBOR was higher than the fixed rate in the contract. The Company did not designate the interest rate derivatives as cash flow hedges; therefore, the changes in fair value of these instruments were recorded in current earnings. In prior years, the Company had one interest rate swap and one interest rate cap outstanding for a notional amount of $100.0 million with fixed pay rates of 1.11% and 3.00%, respectively, until their expiration in September 2013. No interest rate derivatives were in place as of December 31, 2015 or 2014.
c. Balance sheet presentation
In accordance with the Company's standard practice, its commodity derivatives are subject to counterparty netting under agreements governing such derivatives. The Company's oil and natural gas commodity derivatives are presented on a net basis as "Derivatives" on the consolidated balance sheets. See Note 9.a for a summary of the fair value of derivatives on a gross basis.
By using derivatives to hedge exposures to changes in commodity prices and interest rates, the Company exposes itself to credit risk and market risk. For the Company, market risk is the exposure to changes in the market price of oil and natural gas, which are subject to fluctuations from a variety of factors, including changes in supply and demand. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Company, thereby creating credit risk. The Company's counterparties are participants in the
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Senior Secured Credit Facility, which is secured by the Company's oil and natural gas reserves; therefore, the Company is not required to post any collateral. The Company does not require collateral from its derivative counterparties. The Company minimizes the credit risk in derivatives by: (i) limiting its exposure to any single counterparty, (ii) entering into derivatives only with counterparties that meet the Company's minimum credit quality standard or have a guarantee from an affiliate that meets the Company's minimum credit quality standard and (iii) monitoring the creditworthiness of the Company's counterparties on an ongoing basis.
Note 9-Fair value measurements
The Company accounts for its oil and natural gas commodity derivatives and, in prior periods, its interest rate derivatives, at fair value. The fair value of derivatives is determined utilizing pricing models for similar instruments. The models use a variety of techniques to arrive at fair value, including quotes and pricing analysis. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
The Company has categorized its assets and liabilities measured at fair value, based on the priority of inputs to the valuation technique, into a three-level fair value hierarchy. The fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
Assets and liabilities recorded at fair value on the consolidated balance sheets are categorized based on inputs to the valuation techniques as follows:
Level 1-
Assets and liabilities recorded at fair value for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. Active markets are considered to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2-
Assets and liabilities recorded at fair value for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the assets or liabilities. Substantially all of these inputs are observable in the marketplace throughout the full term of the price risk management instrument and can be derived from observable data or supported by observable levels at which transactions are executed in the marketplace.
Level 3-
Assets and liabilities recorded at fair value for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. Unobservable inputs are not corroborated by market data. These inputs reflect management's own assumptions about the assumptions a market participant would use in pricing the asset or liability.
When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. The Company conducts a review of fair value hierarchy classifications on an annual basis. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. Transfers between fair value hierarchy levels are recognized and reported in the period in which the transfer occurred. No transfers between fair value hierarchy levels occurred during the years ended December 31, 2015, 2014 or 2013.
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Notes to the consolidated financial statements
a. Fair value measurement on a recurring basis
The following tables summarize the Company's fair value hierarchy by commodity on a gross basis and the net presentation on the consolidated balance sheets for derivative assets and liabilities measured at fair value on a recurring basis as of the periods presented:
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Notes to the consolidated financial statements
These items are included as "Derivatives" on the consolidated balance sheets. Significant Level 2 assumptions associated with the calculation of discounted cash flows used in the mark-to-market analysis of commodity derivatives include each derivative contract's corresponding commodity index price, appropriate risk-adjusted discount rates and other relevant data.
The Company's deferred premiums associated with its commodity derivative contracts are categorized as Level 3, as the Company utilizes a net present value calculation to determine the valuation. They are considered to be measured on a recurring basis as the derivative contracts they derive from are measured on a recurring basis. As commodity derivative contracts containing deferred premiums are entered into, the Company discounts the associated deferred premium to its net present value at the contract trade date, using the Senior Secured Credit Facility rate at the trade date (historical input rates range from 1.69% to 3.56%), and then records the change in net present value to interest expense over the period from trade until the final settlement date at the end of the contract. After this initial valuation, the net present value of each deferred premium is not adjusted; therefore, significant increases (decreases) in the Senior Secured Credit Facility rate would result in a significantly lower (higher) fair value measurement for each new contract entered into that contained a deferred premium; however, the valuation for the deferred premiums already recorded would remain unaffected. While the Company believes the sources utilized to arrive at the fair value estimates are reliable, different sources or methods could have yielded different fair value estimates; therefore, on a quarterly basis, the valuation is compared to counterparty valuations and a third-party valuation of the deferred premiums for reasonableness.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The following table presents actual cash payments required for deferred premiums for the calendar years presented:
A summary of the changes in assets classified as Level 3 measurements for the periods presented are as follows:
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(1)
The settlement amount for the year ended December 31, 2013 includes $2.2 million in deferred premiums which were settled net with the early terminated contracts from which they derive.
b. Fair value measurement on a nonrecurring basis
The Company accounts for the impairment of long-lived assets, if any, at fair value on a nonrecurring basis. For purposes of fair value measurement, it was determined that the impairment of long-lived assets is classified as Level 3, based on the use of internally developed cash flow models. See Note 2.j for discussion of the Company's impairment of line-fill, materials and supplies and other fixed assets for the periods presented.
The accounting policies for impairment of oil and natural gas properties are discussed in Note 2.g. Significant inputs included in the calculation of discounted cash flows used in the impairment analysis include the Company's estimate of operating and development costs, anticipated production of evaluated reserves and other relevant data. See Note 2.g for discussion regarding the prices used in the calculation of discounted cash flows and the Company's second, third and fourth-quarter 2015 full cost ceiling impairments.
Note 10-Net income (loss) per share
Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, performance share awards and outstanding restricted stock options. For the year ended December 31, 2015, all of these potentially dilutive items were anti-dilutive due to the Company's net loss and, therefore, were excluded from the calculation of diluted net income (loss) per share.
The effects of the Company's then outstanding restricted stock options that were granted in February 2014 to purchase 336,140 shares of common stock at $25.60 per share and in February 2012 to purchase 280,626 shares of common stock at $24.11 per share were excluded from the calculation of diluted net income per share for each of the years ended December 31, 2014 and 2013, because the exercise prices of these options were greater than the average market price during the period, and, therefore, the inclusion of these outstanding options would have been anti-dilutive.
The effect of the Company's outstanding restricted stock options that were granted in February 2013 to purchase 750,338 shares of common stock at $17.34 per share was excluded from the calculation of diluted net income per share for the years ended December 31, 2014 and 2013, because, utilizing the treasury method, the sum of the assumed proceeds exceeded the average stock price during the period and, therefore, the inclusion of these outstanding options would have been anti-dilutive. For the year ended December 31, 2014, the 2014 Performance Share Awards' total shareholder return was below their agreement's payout threshold, and therefore the 2014 Performance Share Awards were excluded from the calculation of diluted net income per share. There were no outstanding performance share awards in 2013.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The following is the calculation of basic and diluted weighted-average common shares outstanding and net income (loss) per share for the periods presented:
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(1)
For the year ended December 31, 2015, weighted-average common shares outstanding used in the computation of basic and diluted net loss per share attributable to stockholders was computed taking into account the March 2015 Equity Offering. For the year ended December 31, 2013, weighted-average common shares outstanding used in the computation of basic and diluted net income per share attributable to stockholders was computed taking into account the August 2013 Equity Offering.
Note 11-Credit risk
The Company's oil, NGL and natural gas sales are made to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. The Company's joint operations accounts receivable are from a number of oil and natural gas companies, partnerships, individuals and others who own interests in the oil and natural gas properties operated by the Company. The Company's sales of purchased oil are made to one customer. Management believes that any credit risk imposed by a concentration in the oil and natural gas industry is offset by the creditworthiness of the Company's customer base and industry partners. The Company routinely assesses the recoverability of all material trade and other receivables to determine collectability.
The Company uses derivatives to hedge its exposure to oil and natural gas price volatility and, in prior periods, its exposure to interest rate risk associated with the Senior Secured Credit Facility. These transactions expose the Company to potential credit risk from its counterparties. In accordance with the Company's standard practice, its derivatives are subject to counterparty netting under agreements governing such derivatives; therefore, the credit risk associated with its derivative counterparties is somewhat mitigated. See Notes 2.f, 8 and 9 for additional information regarding the Company's derivatives.
For the year ended December 31, 2015, the Company had two customers that accounted for 37.5% and 20.3% of total oil, NGL and natural gas sales, with each customer accounting for 35.3% and 23.7%, respectively, of oil, NGL and natural gas sales accounts receivable, and two other customers accounting for 18.5% and 10.7% of oil, NGL and natural gas sales accounts receivable as of December 31, 2015. For the year ended December 31, 2014, the Company had two customers that accounted for 36.0% and 13.7% of total oil, NGL and natural gas sales, with each customer accounting for 16.4% and 22.5%, respectively, of oil, NGL and natural gas sales accounts receivable, and three other customers accounting for 13.5%, 12.5% and 11.6% of oil, NGL and natural gas sales accounts receivable as of December 31, 2014. For the year ended December 31, 2013, the Company had three customers that accounted for 28.3%, 11.7% and 11.7% of total oil, NGL and natural gas sales, with two of the three
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Notes to the consolidated financial statements
customers accounting for 36.0% and 15.7% of oil and natural gas sales accounts receivable as of December 31, 2013. These customers and percentages reported are related to the Company's exploration and production segment, see Note 17.
As of December 31, 2015, the Company had two partners whose joint operations accounts receivable accounted for 18.9% and 17.1% of the Company's total joint operations accounts receivable. As of December 31, 2014, the Company had two partners whose joint operations accounts receivable accounted for 20.5% and 13.2% of the Company's total joint operations accounts receivable. These customers and percentages reported are related to the Company's exploration and production segment, see Note 17.
For the year ended December 31, 2015, the Company had one customer that accounted for 100.0% of total sales of purchased oil, with the same customer accounting for 99.6% of purchased oil and other product sales receivable as of December 31, 2015. For the year ended December 31, 2014, the Company had one customer that accounted for 100.0% of total sales of purchased oil, with the same customer accounting for 97.3% of purchased oil and other product sales receivable as of December 31, 2014. There were no comparable sales of purchased oil for the year ended December 31, 2013 and correspondingly, there was no purchased oil and other product sales receivable as of December 31, 2013. The customer and percentages reported relate to the Company's midstream and marketing segment, see Note 17.
The Company's cash balances are insured by the FDIC up to $250,000 per bank. The Company had cash balances on deposit with certain banks as of December 31, 2015, which exceeded the balance insured by the FDIC in the amount of $51.3 million. Management believes that the risk of loss is mitigated by the banks' reputation and financial position.
Note 12-Commitments and contingencies
a. Lease commitments
The Company leases office space under operating leases expiring on various dates through 2027. Minimum annual lease commitments for the calendar years presented are:
The following has been recorded to rent expense for the periods presented:
The Company's office space lease agreements contain scheduled escalation in lease payments during the term of the lease. In accordance with GAAP, the Company records rent expense on a straight-line basis and a deferred lease liability for the difference between the straight-line amount and the actual amounts of the lease payments. Rent expense is included in the consolidated statements of operations in the "General and administrative" line item.
b. Litigation
From time to time the Company is involved in legal proceedings and/or may be subject to industry rulings that could bring rise to claims in the ordinary course of business. The Company has concluded that the likelihood is remote that the ultimate resolution of any pending litigation or pending claims will be material or have a material adverse effect on the Company's business, financial position, results of operations or liquidity.
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Notes to the consolidated financial statements
c. Drilling contracts
The Company has committed to drilling contracts with various third parties to complete its various drilling projects. The contracts contain early termination clauses that require the Company to potentially pay penalties to third parties should the Company cease drilling efforts. These penalties would negatively impact the Company's financial statements upon early contract termination, especially if a significant number of such contracts were terminated early in their respective terms. In the fourth quarter of 2014, the Company announced a reduced 2015 capital expenditure budget compared to 2014. As a result, the Company began releasing rigs as drilling contracts came close to expiration and incurred charges of $0.5 million which were recorded for the year ended December 31, 2014 on the consolidated statements of operations as "Drilling rig fees." No comparable amounts were recorded in the years ended December 31, 2015 or 2013. Future commitments of $10.3 million as of December 31, 2015 are not recorded in the accompanying consolidated balance sheets. Management does not currently anticipate the early termination of any existing contracts in 2016 that would result in a substantial penalty.
d. Firm sale and transportation commitments
The Company has committed to deliver for sale or transportation fixed volumes under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. If not fulfilled, the Company is subject to minimal volume penalties. These commitments are normal and customary for the Company's business. Future commitments of $425.7 million as of December 31, 2015 are not recorded in the accompanying consolidated balance sheets. The Company's production has been equivalent or greater than its delivery commitments during the three most recent years, and management expects such production will continue to exceed the Company's future commitments. However, in certain instances, the Company has used spot market purchases to meet its commitments in certain locations or due to favorable pricing. Management anticipates continuing this practice in the future. Also, if production is not sufficient to satisfy the Company's delivery commitments, the Company can and may use spot market purchases to fulfill the commitments.
e. Federal and state regulations
Oil and natural gas exploration, production and related operations are subject to extensive federal and state laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases the cost of doing business and affects profitability. The Company believes that it is in compliance with currently applicable federal and state regulations related to oil and natural gas exploration and production, and that compliance with the current regulations will not have a material adverse impact on the financial position or results of operations of the Company. These rules and regulations are frequently amended or reinterpreted; therefore, the Company is unable to predict the future cost or impact of complying with these regulations.
f. Other commitments
See Notes 2.u, 16.a and 19.b for the amount of and discussion regarding outstanding commitments to the Company's non-consolidated variable interest entity ("VIE").
Note 13-Restructuring
Following the fourth-quarter 2014 drop in oil prices, in an effort to reduce costs and to better position the Company for ongoing efficient growth, on January 20, 2015, the Company executed a company-wide restructuring and reduction in force (the "RIF") that included (i) the relocation of certain employees from the Company's Dallas, Texas area office to the Company's other existing offices in Tulsa, Oklahoma and Midland, Texas; (ii) closing the Company's Dallas, Texas area office; (iii) a workforce reduction of approximately 75 employees and (iv) the release of 24 contract personnel. The RIF was communicated to employees on January 20, 2015 and was generally effective immediately. The Company's compensation committee approved the RIF and the related severance package. The Company incurred $6.0 million in expenses during the year ended December 31, 2015 related to the RIF. There were no comparative amounts recorded in the years ended December 31, 2014 or 2013.
Note 14-Recently issued accounting standards
In November 2015, the Financial Accounting Standards Board ("FASB") issued new guidance in Topic 740, Income Taxes, which seeks to simplify the presentation of deferred income taxes. The amendments in this update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. For public business entities, the amendments in this update are effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted as of the beginning of an interim or annual reporting period. The amendments in this update may be applied either prospectively to all deferred tax liabilities and assets or retrospectively to all periods presented. The Company has early-adopted this standard as of December 31, 2015, and
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Notes to the consolidated financial statements
has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of deferred income taxes from the current liabilities "Deferred income taxes" to the noncurrent liabilities "Deferred income taxes" within the consolidated balance sheets.
The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below:
See Note 7 for additional discussion of the December 31, 2014 consolidated balance sheet presentation reclassification.
In July 2015, the FASB issued new guidance in Topic 330, Inventory, which seeks to simplify the measurement of inventory. The amendments in this update apply to inventory that is measured using all methods excluding last-in, first-out and the retail inventory method. The main substantive provision of this guidance is for an entity to change the subsequent measurement of inventory, within the scope of this guidance, from LCM to the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The amendments in this update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within those fiscal years and should be applied prospectively with earlier application permitted as of the beginning of an interim or annual reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.
In April 2015, the FASB issued new guidance in Subtopic 835-30, Interest-Imputation of Interest, which seeks to simplify the presentation of debt issuance costs. These amendments require that debt issuance costs related to a recognized debt liability be presented in an entity's balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this guidance. Entities should apply the amendments on a retrospective basis, wherein the balance sheet of each individual period presented should be adjusted to reflect the period-specific effects of applying the new guidance. The Company has early-adopted this standard as of September 30, 2015, and has applied its provisions retrospectively. The adoption of this standard resulted in the reclassification of (i) the unamortized debt issuance costs related to the Company's senior unsecured notes from noncurrent assets "Debt issuance costs, net" to noncurrent liabilities "Long-term debt, net" and (ii) the unamortized debt issuance costs related to the Company's Senior Secured Credit Facility from noncurrent assets "Debt issuance costs, net" to noncurrent assets "Other assets, net" within the consolidated balance sheets. See Notes 2.k and 5.h for additional discussion of debt issuance costs.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The changes to the line items in the consolidated balance sheets as of the previously reported interim periods, as if this standard had been adopted in first-quarter 2015, are presented below:
In May 2014, the FASB issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition. The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.
Note 15-Variable interest entity
An entity is referred to as a VIE pursuant to accounting guidance for consolidation if it possesses one of the following criteria: (i) it is thinly capitalized, (ii) the residual equity holders do not control the entity, (iii) the equity holders are shielded from the economic losses, (iv) the equity holders do not participate fully in the entity's residual economics, or (v) the entity was established with non-substantive voting interests. In order to determine if a VIE should be consolidated, an entity must determine if it is the primary beneficiary of the VIE. The primary beneficiary of a VIE is that variable interest-holder possessing a controlling financial interest through: (i) its power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether the Company owns a variable interest in a VIE, a qualitative analysis is performed of the entity's design, organizational structure, primary decision makers and relevant agreements. The Company continually monitors its VIE exposure to determine if any events have occurred that could cause the primary beneficiary to change.
LMS contributed $99.9 million and $55.2 million during the years ended December 31, 2015 and 2014, respectively, to Medallion Gathering & Processing, LLC, a Texas limited liability company formed on October 12, 2012, and its wholly-owned subsidiaries (together, "Medallion"). See Note 19.b for discussion regarding a contribution made to Medallion subsequent to December 31, 2015.
LMS holds 49% of Medallion ownership units. Medallion was established for the purpose of developing midstream solutions and providing midstream infrastructure to bring oil, NGL and natural gas to market. LMS and the other 51% interest-holder have agreed that the voting rights of Medallion, the profit and loss sharing, and the additional capital contribution requirements shall be equal to the ownership unit percentage held. Additionally, Medallion requires a super-majority vote of 75% for all key operating and business decisions. The Company has determined that Medallion is a VIE. However, LMS is not considered to be the primary beneficiary of the VIE because LMS does not have the power to direct the activities that most significantly affect Medallion's economic performance. As such, Medallion is accounted for under the equity method of accounting with the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations as "Income (loss) from equity method investee" and the carrying amount reflected in the consolidated balance sheets as "Investment in equity method investee."
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
During the year ended December 31, 2015, Medallion continued expansion activities on existing portions of its pipeline infrastructure in order to gather additional third-party oil production and began recognizing revenue due to its main pipeline becoming operational.
During the year ended December 31, 2015, the Company negotiated a buyout of a minimum volume commitment to Medallion, which was related to natural gas gathering infrastructure Medallion constructed on acreage that the Company does not plan to develop. The portion of the buyout that was related to the Company's minimum volume commitment for future periods was $3.0 million and is included in the consolidated statements of operations in the line item "Minimum volume commitments" for the period in which the buyout was settled. See Note 16.a for discussion of items included in the consolidated financial statements related to Medallion.
The following table summarizes items included in Medallion's consolidated statements of operations, which are not recorded in the Company's consolidated financial statements, for the periods presented:
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(1)
Medallion's pipeline did not become operational until 2015, accordingly no costs of good sold were recorded for the years ended December 31, 2014 and 2013.
(2)
As Medallion's financial statements are unaudited at the time of filing the Company's Annual Report on Form 10-K, the Company's proportionate share of Medallion's net income (loss) reflected in the consolidated statements of operations for the years ended December 31, 2015 and 2014 include immaterial prior period Medallion audit adjustments.
(3)
Medallion's consolidated statement of operations for the year ended December 31, 2015 was unaudited as of February 17, 2016.
The following table summarizes items included in Medallion's consolidated balance sheets, which are not recorded in the Company's consolidated financial statements, as of the periods presented:
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(1)
Medallion's consolidated balance sheet as of December 31, 2015 was unaudited as of February 17, 2016.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Note 16-Related Parties
a. Medallion
The following table summarizes items included in the consolidated statements of operations related to Medallion for the periods presented:
The following table summarizes items included in the consolidated balance sheets related to Medallion as of the periods presented:
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(1)
Amounts included in "Other assets, net" above represent LMS owned line-fill in Medallion's pipeline.
(2)
Amounts included in "Other current liabilities" above for the year ended December 31, 2015 represents LMS's capital contribution payable to Medallion, of which a portion was paid subsequent to December 31, 2015. "Other current liabilities" above for the year ended December 31, 2014 represents LMS's minimum volume commitment payable to Medallion. See Note 15 for additional discussion of Medallion and Note 19.b for additional discussion of the subsequent payment to Medallion.
b. Targa Resources Corp.
The Company has a gathering and processing arrangement with affiliates of Targa Resources Corp. ("Targa"). One of Laredo's directors was on the board of directors of Targa until May 18, 2015.
The following table summarizes the oil, NGL and natural gas sales and midstream service revenues received from Targa and included in the consolidated statements of operations for the periods presented:
The following table summarizes the amounts included in accounts receivable, net from Targa in the consolidated balance sheets as of the periods presented:
c. Archrock Partners, L.P.
The Company has a compression arrangement with affiliates of Archrock Partners, L.P., formerly Exterran Partners L.P., ("Archrock"). One of Laredo's directors is on the board of directors of Archrock GP LLC, an affiliate of Archrock.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
The following table summarizes the lease operating expenses related to Archrock included in the consolidated statements of operations for the periods presented:
The following table summarizes the capital expenditures related to Archrock included in the consolidated statements of cash flows for the periods presented:
The following table summarizes the amounts included in accounts payable from Archrock in the consolidated balance sheets as of the periods presented:
d. Helmerich & Payne, Inc.
The Company has had drilling contracts with Helmerich & Payne, Inc. ("H&P"). Laredo's Chairman and Chief Executive Officer is on the board of directors of H&P.
The following table summarizes the capitalized oil and natural gas properties related to H&P and included in the consolidated statements of cash flows for the periods presented:
Note 17-Segments
Since the beginning of 2015, the Company has presented financial results by segment to highlight the growing value of its midstream and marketing segment and the midstream and marketing segment's interest in Medallion, as Medallion's third-party revenues have increased.
The Company operates in two business segments, which are (i) exploration and production and (ii) midstream and marketing. The exploration and production segment is engaged in the acquisition, exploration and development of oil and natural gas properties. The midstream and marketing segment provides Laredo's exploration and production segment and certain third parties with (i) products and services that need to be delivered by midstream infrastructure, including oil and natural gas gathering services as well as rig fuel, natural gas lift and water in and around Laredo's primary production corridors, (ii) water takeaway in and around Laredo's primary production corridors and (iii) oil and natural gas takeaway optionality in the field coupled with firm service commitments to maximize Laredo's oil, NGL and natural gas revenues.
The following table presents selected financial information, for the periods presented, regarding the Company's operating segments on a stand-alone basis and the consolidation and elimination entries necessary to arrive at the information for the Company on a consolidated basis:
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Notes to the consolidated financial statements
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(1)
General and administrative costs were allocated based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013. Certain components of general and administrative costs were not allocated and were based on actual costs for each segment, which primarily consisted of payroll, deferred
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Notes to the consolidated financial statements
compensation and vehicle costs for the years ended December 31, 2015 and 2014 and payroll and deferred compensation for the year ended December 31, 2013. Costs associated with land and geology were not allocated to the midstream and marketing segment for the years ended December 31, 2015, 2014 and 2013.
(2)
Depletion, depreciation and amortization were based on actual costs for each segment with the exception of the allocation of depreciation of other fixed assets, which was based on the number of employees in the respective segment for the years ended December 31, 2015, 2014 and 2013.
(3)
Other operating costs and expenses include restructuring expense and accretion of asset retirement obligations for the year ended December 31, 2015, accretion of asset retirement obligations and drilling rig fees for the year ended December 31, 2014 and accretion of asset retirement obligations for the year ended December 31, 2013. These expenses are based on actual costs and are not allocated.
(4)
Interest expense was allocated to the exploration and production segment based on gross property and equipment for the years ended December 31, 2015, 2014 and 2013 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the years ended December 31, 2015, 2014 and 2013.
(5)
Loss on early redemption of debt was allocated to the exploration and production segment based on gross property and equipment for the year ended December 31, 2015 and allocated to the midstream and marketing segment based on gross property and equipment and life-to-date contributions to the Company's equity method investee for the year ended December 31, 2015.
(6)
Income tax benefit or expense for the midstream and marketing segment was calculated by multiplying income (loss) from continuing operations before income taxes by 36% for the years ended December 31, 2015, 2014 and 2013.
(7)
Capital expenditures exclude acquisition of oil and natural gas properties and acquisition of mineral interests for the year ended December 31, 2014 and excludes acquisitions of oil and natural gas properties for the year ended December 31, 2013.
(8)
Gross property and equipment for the midstream and marketing segment includes investment in equity method investee totaling $192.5 million, $58.3 million and $5.9 million as of December 31, 2015, 2014 and 2013, respectively. Other fixed assets were allocated based on the number of employees in the respective segment as of December 31, 2015, 2014 and 2013.
Note 18-Subsidiary guarantors
The Guarantors have fully and unconditionally guaranteed the January 2022 Notes, the May 2022 Notes, the March 2023 Notes and the Senior Secured Credit Facility (and had guaranteed the January 2019 Notes until the Redemption Date), subject to the Releases. In accordance with practices accepted by the SEC, Laredo has prepared condensed consolidating financial statements to quantify the assets, results of operations and cash flows of such subsidiaries as subsidiary guarantors. The following condensed consolidating balance sheets as of December 31, 2015 and 2014, and condensed consolidating statements of operations and condensed consolidating statements of cash flows each for the years ended December 31, 2015, 2014 and 2013, present financial information for Laredo on a stand-alone basis (carrying any investment in subsidiaries under the equity method), financial information for the subsidiary guarantors on a stand-alone basis (carrying any investment in subsidiaries under the equity method), and the consolidation and elimination entries necessary to arrive at the information for the Company on a condensed consolidated basis. Deferred income taxes for LMS and for GCM are recorded on Laredo's statements of financial position, statements of operations and statements of cash flows as they are disregarded entities for income tax purposes. Laredo and the Guarantors are not restricted from making intercompany distributions to each other. During the year ended December 31, 2014, certain midstream service assets were transferred from Laredo to LMS at historical cost.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Condensed consolidating balance sheet
December 31, 2015
Condensed consolidating balance sheet
December 31, 2014
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Condensed consolidating statement of operations
For the year ended December 31, 2015
Condensed consolidating statement of operations
For the year ended December 31, 2014
Condensed consolidating statement of operations
For the year ended December 31, 2013
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
Condensed consolidating statement of cash flows
For the year ended December 31, 2015
Condensed consolidating statement of cash flows
For the year ended December 31, 2014
Condensed consolidating statement of cash flows
For the year ended December 31, 2013
Note 19-Subsequent events
a. Senior Secured Credit Facility
On January 14, 2016, the Company borrowed $35.0 million on the Senior Secured Credit Facility. The outstanding balance under the Senior Secured Credit Facility was $170.0 million at February 16, 2016.
b. Medallion capital call
On January 15 and February 16, 2016, the Company made additional capital contributions to Medallion of $12.7 million and $8.3 million, respectively, which represent LMS's remaining commitment for the extension from Medallion's Garden City Station to Midland and Upton counties, Texas and a portion of the commitment for the southern extension from Medallion's Reagan Station further into Reagan County, Texas.
Laredo Petroleum, Inc.
Notes to the consolidated financial statements
c. New commodity derivative contracts
Subsequent to December 31, 2015, the Company entered into the following new commodity derivative contracts:
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(1)
The associated commodity derivatives will be settled based on the Inside FERC index price for West Texas Waha. There are $4.3 million in deferred premiums associated with these contracts.
Note 20-Supplemental oil, NGL and natural gas disclosures
a. Costs incurred in oil, NGL and natural gas property acquisition, exploration and development activities
Costs incurred in the acquisition, exploration and development of oil, NGL and natural gas assets are presented below:
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(1)
The Company acquired significant leasehold interests during the year ended December 31, 2014.
(2)
The costs incurred for oil, NGL and natural gas development activities include $13.4 million, $6.9 million and $6.8 million in asset retirement obligations for the years ended December 31, 2015, 2014 and 2013, respectively.
b. Capitalized oil, NGL and natural gas costs
Aggregate capitalized costs related to oil, NGL and natural gas production activities with applicable accumulated depletion and impairment are presented below:
The following table shows a summary of the oil, NGL and natural gas property costs not being depleted as of December 31, 2015, by year in which such costs were incurred:
Unevaluated properties, which are not subject to depletion, are not individually significant and consist of costs for acquiring oil, NGL and natural gas leaseholds where no evaluated reserves have been identified, including costs of wells being
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
evaluated. The evaluation process associated with these properties has not been completed and therefore, the Company is unable to estimate when these costs will be included in the depletion calculation.
c. Results of oil, NGL and natural gas producing activities
The results of operations of oil, NGL and natural gas producing activities (excluding corporate overhead and interest costs) are presented below:
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(1)
During the year ended December 31, 2015, the Company recorded a valuation allowance against its deferred tax assets related to its oil, NGL and natural gas producing activities. Accordingly, for the year ended December 31, 2015, income tax benefit is computed utilizing the Company's effective rate of 7%, which reflects tax deductions and tax credits and allowances relating to the oil, NGL and natural gas producing activities that are reflected in the Company's consolidated income tax benefit for the period. For the years ended December 31, 2014 and 2013, income tax expense is computed utilizing the statutory rate.
d. Net proved oil, NGL and natural gas reserves - (unaudited)
Ryder Scott Company, L.P. ("Ryder Scott"), the Company's independent reserve engineers, estimated 100% of the Company's proved reserves as of December 31, 2015, 2014 and 2013. In accordance with SEC regulations, reserves as of December 31, 2015, 2014 and 2013 were estimated using the Realized Prices (which are the Benchmark Prices adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead), see Note 2.g. The Company's reserves as of December 31, 2015 are reported in three streams: oil, NGL and natural gas. The Company's reserves as of December 31, 2014 and 2013 are reported in two streams: oil and liquids-rich natural gas with the economic value of the NGLs in the Company's natural gas included in the wellhead natural gas price. This change impacts the comparability of 2015 with prior periods. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil, NGL and natural gas properties. Accordingly, the estimates may change as future information becomes available.
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
The following tables provide an analysis of the changes in estimated reserve quantities of oil, NGL and natural gas for the year ended December 31, 2015 and of oil and liquids-rich natural gas for the years ended December 31, 2014 and 2013, all of which are located within the United States.
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(1)
The positive NGL revisions of previous estimates and the negative natural gas revisions of previous estimates include the impact of the Company's conversion to three-stream production. For periods prior to January 1, 2015, the Company presented its reserves for oil and natural gas, which combined NGL with the natural gas stream, and did not separately report NGL. This change impacts the comparability to prior periods.
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
For the year ended December 31, 2015, the Company's negative revision of 124,180 MBOE of previously estimated quantities is primarily attributable to the removal of 106,883 MBOE due to the combined effect of the removal of 378 proved undeveloped locations and the net effect of reinterpreting 34 undeveloped locations. The 378 locations that were removed were comprised of 182 vertical Wolfberry wells due to lower commodity prices and 196 horizontal wells to better align the timing of their development with the Company's future drilling plans. The remaining 17,297 MBOE of negative revisions is due to a combination of pricing, performance and other changes to the proved developed producing and proved developed non-producing wells. Extensions, discoveries and other additions of 22,388 MBOE during the year ended December 31, 2015, consisted of 19,719 MBOE primarily from the drilling of new wells during the year and 2,669 MBOE from four new horizontal Middle Wolfcamp proved undeveloped locations added during the year.
For the year ended December 31, 2014, the Company's negative revision of 21,359 MBOE of previously estimated quantities is primarily attributable to the removal of 26,017 MBOE due to the combined effect of the removal of 226 proved undeveloped locations and the net effect of reinterpreting 345 undeveloped locations. The 226 locations that were removed were comprised of vertical Wolfberry and horizontal laterals to better align with the proved developed producing wells. The increase of 4,658 MBOE, which offsets the overall negative revision, is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 76,539 MBOE during the year ended December 31, 2014, consisted of 34,782 MBOE primarily from the drilling of new wells during the year and 41,757 MBOE from 113 new horizontal proved undeveloped locations added during the year. Purchases of minerals in place added 256 MBOE from acquisition of proved reserves in the Permian Basin.
For the year ended December 31, 2013, the Company's negative revision of 15,338 MBOE of previously estimated quantities is primarily attributable to the removal of 11,944 MBOE due to the combined effect of the removal of 174 proved undeveloped locations and the net effect of reinterpreting 501 undeveloped locations. The 174 locations that were removed were comprised of vertical Wolfberry and short horizontal laterals which were replaced with longer horizontal laterals to better align with future drilling plans. The remaining 3,394 MBOE of the negative revision is due to a combination of pricing, performance and other changes. Extensions, discoveries and other additions of 69,888 MBOE during the year ended December 31, 2013, consisted of 22,245 MBOE primarily from the drilling of new wells during the year and 47,643 MBOE from new proved undeveloped locations added during the year. The latter consists of 45,510 MBOE attributable to 85 horizontal locations in the Permian Basin. Purchases of minerals in place added 412 MBOE from acquisition of proved reserves in the Permian Basin.
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
e. Standardized measure of discounted future net cash flows - (unaudited)
The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil, NGL and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of proved properties, and consideration of expected future economic and operating conditions.
The estimates of future cash flows and future production and development costs as of December 31, 2015, 2014 and 2013 are based on the Realized Prices, which reflect adjustments to the Benchmark Prices for gravity, quality, local conditions, fuel and shrinkage and/or distance from market. All Realized Prices are held flat over the forecast period for all reserve categories in calculating the discounted future net revenues. Any effect from the Company's commodity hedges is excluded. In accordance with SEC regulations, the proved reserves were anticipated to be economically producible from the "as of date" forward based on existing economic conditions, including prices and costs at which economic producibility from a reservoir was determined. These costs, held flat over the forecast period, include development costs, operating costs, ad valorem and production taxes and abandonment costs after salvage. Future income tax expenses are computed using the appropriate year-end statutory tax rates applied to the future pretax net cash flows from proved oil, NGL and natural gas reserves, less the tax basis of the Company's oil, NGL and natural gas properties. The estimated future net cash flows are then discounted at a rate of 10%. The Company's net book value of evaluated oil, NGL and natural gas properties exceeded the full cost ceiling amount as of June 30, 2015, September 30, 2015 and December 31, 2015. See Note 2.g for discussion of the Benchmark Prices, Realized Prices and the corresponding non-cash full cost ceiling impairments recorded.
The standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves is as follows:
It is not intended that the FASB's standardized measure of discounted future net cash flows represent the fair market value of the Company's proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, prices and costs as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
Laredo Petroleum, Inc.
Supplemental oil and natural gas disclosures
Changes in the standardized measure of discounted future net cash flows relating to proved oil, NGL and natural gas reserves are as follows:
Estimates of economically recoverable oil, NGL and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are, to some degree, subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil, NGL and natural gas may differ materially from the amounts estimated.
Note 21-Supplemental quarterly financial data - (unaudited)
The Company's results from continuing operations by quarter for the periods presented are as follows: