þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2016 | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to |
Delaware | 16-1751069 |
(State or other jurisdiction of | (I.R.S. Employer |
incorporation or organization) | Identification No.) |
303 W. Wall Street, Suite 1800 | 79701 |
Midland, Texas | (Zip Code) |
(Address of principal executive offices) |
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o | Smaller reporting company o |
(Do not check if a smaller reporting company) |
PART I | ||
ITEM 1. | ||
ITEM 1A. | ||
ITEM 1B. | ||
ITEM 2. | ||
ITEM 3. | ||
ITEM 4. | ||
PART II | ||
ITEM 5. | ||
ITEM 6. | ||
ITEM 7. | ||
ITEM 7A. | ||
ITEM 8. | ||
ITEM 9. | ||
ITEM 9A. | ||
ITEM 9B. | ||
PART III | ||
ITEM 10. | ||
ITEM 11. | ||
ITEM 12. | ||
ITEM 13. | ||
ITEM 14. | ||
PART IV | ||
ITEM 15. | ||
ITEM 16. |
• | our business strategy; |
• | the amount of oil and natural gas we produce; |
• | the price at which we are able to sell our oil and natural gas production; |
• | our ability to acquire and appropriately finance additional oil and natural gas properties at economically attractive prices; |
• | our drilling locations and our ability to continue our development activities at economically attractive costs; |
• | the level of our lease operating expenses, general and administrative costs and finding and development costs, including payments to our general partner; |
• | the level of our capital expenditures; |
• | our ability to comply with, renegotiate or receive waivers of debt covenants under our revolving credit facility and our term loan credit agreement; |
• | our ability to engage in capital markets activity which may include debt or equity exchanges or repurchases; |
• | our ability to resume cash distributions to our limited partners; |
• | our future operating results; and |
• | our plans, objectives, expectations and intentions. |
ITEM 1. | BUSINESS |
• | we had proved reserves of approximately 144.8 MMBoe, of which 72% were natural gas, 28% were oil and natural gas liquids (“NGLs”) and 94% were classified as proved developed producing; and |
• | our proved reserves to production ratio was approximately 9.4 years based on the annualized production volumes for the three months ended December 31, 2016. |
• | Add proved reserves and maximize cash flow and production through development projects and operational efficiencies; |
• | Make accretive acquisitions of oil and natural gas properties; and |
• | Reduce commodity price risk through oil and natural gas derivative transactions. |
Proved Reserves by Operating Region as of December 31, 2016 | |||||||||||||||||||||
Operating Regions | Oil (MBbls) | Natural Gas (MMcf) | NGLs(MBbls) | Total (MBoe) | % Liquids | % PDP | % Total | ||||||||||||||
East Texas | 63 | 339,034 | 95 | 56,664 | 0.3 | % | 98.1 | % | 39.1 | % | |||||||||||
Permian Basin | 25,491 | 89,446 | 932 | 41,331 | 63.9 | % | 83.4 | % | 28.6 | % | |||||||||||
Rocky Mountain | 4,970 | 188,277 | 4,474 | 40,823 | 23.1 | % | 99.2 | % | 28.2 | % | |||||||||||
Mid-Continent | 1,934 | 10,263 | 2,342 | 5,986 | 71.4 | % | 95.6 | % | 4.1 | % | |||||||||||
Total | 32,458 | 627,020 | 7,843 | 144,804 | 27.8 | % | 94.1 | % | 100.0 | % |
Gross Locations | Net Locations | Net Volume (MBoe) | ||||||
Balance, December 31, 2015 | 44 | 17.5 | 2,458 | |||||
PUDs converted to PDP by drilling | (4 | ) | (0.2 | ) | (327 | ) | ||
PUDs removed due to performance (a) | (6 | ) | (0.1 | ) | (137 | ) | ||
PUDs removed from future drilling schedule (b) | (16 | ) | (11.4 | ) | (721 | ) | ||
PUDs removed due to sale | (2 | ) | (1.3 | ) | (138 | ) | ||
Additions due to performance (a) | 31 | 11.9 | 3,872 | |||||
Other | — | 0.6 | 636 | |||||
Balance, December 31, 2016 | 47 | 17.0 | 5,643 |
(a) | PUDs removed or added due to performance are those PUDs removed or added, as applicable, due to new or revised engineering, geologic and economic evaluations such as offset well production data, the drilling of offset wells, new geologic data or changes in projected capital costs or product prices. PUDs are removed or added depending on whether the technical criteria for the proved undeveloped reserve classification is satisfied and, in the case of additions due to performance, whether the well is scheduled to be drilled within five years after initial recognition as proved reserves. |
(b) | These PUD locations were removed from our PUD inventory because we determined, based upon review of our current inventory and as indicated in our future drilling plans, that these PUD locations are not scheduled to be drilled within five years after initial recognition as proved reserves. |
• | At the first instance of Investor achieving a 15% internal rate of return in the aggregate with respect to a tranche of wells, Investor’s interest in the tranche of wells and related infrastructure (except saltwater disposal wells) will revert to 15% of the Operating Partnership’s initial working interest while the remainder will revert to us, and all the remaining undeveloped Subject Assets will revert to us but remain available for future development subject to the Development Agreement. |
2016 | 2015 | 2014 | ||||||
Enterprise (Teppco) Crude Oil, LP | 1 | % | 6 | % | 12 | % | ||
Plains Marketing, LP | 6 | % | 7 | % | 10 | % |
• | require the acquisition of various permits before drilling commences; |
• | restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production activities; |
• | limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and |
• | require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells. |
• | the location of wells; |
• | the method of drilling and casing wells; |
• | the surface use and restoration of properties upon which wells are drilled; |
• | the plugging and abandoning of wells; and |
• | notice to surface owners and other third parties. |
ITEM 1A. | RISK FACTORS |
• | the domestic and foreign supply of and demand for oil and natural gas; |
• | market expectations about future prices of oil and natural gas; |
• | the price and quantity of imports of crude oil and natural gas; |
• | overall domestic and global economic conditions; |
• | political and economic conditions in other oil and natural gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, and acts of terrorism or sabotage; |
• | the willingness and ability of members of the Organization of Petroleum Exporting Countries and other petroleum producing countries to agree to and maintain oil price and production controls; |
• | trading in oil and natural gas derivative contracts; |
• | the level of consumer product demand; |
• | weather conditions and natural disasters; |
• | technological advances affecting energy production and consumption; |
• | domestic and foreign governmental regulations and taxes; |
• | the proximity, cost, availability and capacity of oil and natural gas pipelines and other transportation facilities; |
• | the impact of the U.S. dollar exchange rates on oil and natural gas prices; and |
• | the price and availability of alternative fuels. |
• | third parties’ confidence in our ability to acquire and develop oil and natural gas properties could erode, which could impact our ability to execute on our business strategy; |
• | it may become more difficult to retain, attract or replace key employees; |
• | employees could be distracted from performance of their duties or more easily attracted to other career opportunities; and |
• | our suppliers, vendors and service providers could renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us. |
• | sell assets, including equity interests in our restricted subsidiaries; |
• | pay distributions on, redeem or purchase our units or redeem or purchase our subordinated debt; |
• | make investments; |
• | incur or guarantee additional indebtedness or issue preferred units; |
• | create or incur certain liens; |
• | enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; |
• | consolidate, merge or transfer all or substantially all of our assets; |
• | engage in transactions with affiliates; |
• | create unrestricted subsidiaries; and |
• | engage in certain business activities. |
• | our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on terms acceptable to us; |
• | covenants in our existing and future credit and debt arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities; |
• | our access to the capital markets may be limited; |
• | our borrowing costs may increase; |
• | we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations and future business opportunities; and |
• | our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a continued downturn in our business or the economy generally. |
• | our proved reserves; |
• | the level of oil and natural gas we are able to produce from existing wells; |
• | the prices at which our oil and natural gas are sold; and |
• | our ability to acquire, locate and produce new reserves. |
• | the high cost, shortages or delivery delays of equipment and services; |
• | unexpected operational events; |
• | adverse weather conditions; |
• | facility or equipment malfunctions; |
• | title disputes; |
• | pipeline ruptures or spills; |
• | collapses of wellbore, casing or other tubulars; |
• | unusual or unexpected geological formations; |
• | loss of drilling fluid circulation; |
• | formations with abnormal pressures; |
• | fires; |
• | blowouts, craterings and explosions; and |
• | uncontrollable flows of oil, natural gas or well fluids. |
• | the validity of our assumptions about recoverable reserves, development potential, future production, revenues, capital expenditures, future oil and natural gas prices, operating costs and potential environmental and other liabilities; |
• | an inability to successfully integrate the assets and businesses we acquire; |
• | a decrease in our liquidity by using a portion of our available cash or borrowing capacity under our revolving credit facility and our term loan credit agreement to finance acquisitions; |
• | a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions; |
• | the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate; |
• | the diversion of management’s attention from other business concerns; |
• | the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges; and |
• | the loss of key purchasers. |
• | neither our partnership agreement nor any other agreement requires our Founding Investors or their controlled affiliates, other than our executive officers, to pursue a business strategy that favors us; |
• | our general partner is allowed to take into account the interests of parties other than us, such as our Founding Investors, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our limited partners; |
• | our Founding Investors and their controlled affiliates (other than our executive officers and their controlled affiliates) may engage in competition with us; |
• | our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our limited partners for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing limited partner interests, limited partners consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law; |
• | our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, and reserves, each of which can affect the amount of cash that is distributed to our limited partners; |
• | our general partner determines the amount and timing of any capital expenditures. Such determination can affect the amount of cash that is available to be distributed to our limited partners; |
• | our general partner determines which costs incurred by it and its affiliates are reimbursable by us; |
• | our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; |
• | our general partner intends to limit its liability regarding our contractual and other obligations; |
• | our general partner controls the enforcement of obligations owed to us by it and its affiliates; and |
• | our general partner decides whether to retain separate counsel, accountants, or others to perform services for us. |
• | permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner; |
• | provides that our general partner will not have any liability to us or our limited partners for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership; |
• | provides that our general partner is entitled to make other decisions in “good faith” if it believes that the decision is in our best interest; |
• | provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of limited partners must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our general partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and |
• | provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct. |
• | our limited partners’ proportionate ownership interests in us will decrease; |
• | the amount of cash available for distribution on each unit may decrease; |
• | the relative voting strength of each previously outstanding unit may be diminished; and |
• | the market price of the units may decline. |
• | a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
• | our limited partners’ right to act with other limited partners to take other actions under our partnership agreement constitutes “control” of our business. |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
ITEM 2. | PROPERTIES |
As of December 31, 2016 | |||||||||||||||
Proved Reserves | Standardized Measure | ||||||||||||||
Field or Region | MMBoe | R/P (a) | % Oil and NGLs | Amount (b) | % of Total | ||||||||||
($ in Millions) | |||||||||||||||
East Texas (c) | 56.4 | 11.8 | — | % | $ | 153.2 | 26.6 | % | |||||||
Piceance Basin (d) | 36.1 | 8.1 | 13 | 88.5 | 15.4 | ||||||||||
Spraberry/War San Fields | 9.0 | 14.4 | 69 | 64.5 | 11.2 | ||||||||||
Lea Field | 3.9 | 14.4 | 78 | 46.4 | 8.1 | ||||||||||
Panhandle Field | 3.1 | 9.5 | 73 | 14.2 | 2.5 | ||||||||||
Deep Rock Field | 1.3 | 10.2 | 98 | 12.3 | 2.1 | ||||||||||
Total — Top 6 | 109.8 | 10.3 | 16 | % | $ | 379.1 | 65.9 | % | |||||||
All others | 35.0 | 7.4 | 64 | 196.5 | 34.1 | ||||||||||
Total | 144.8 | 9.4 | 28 | % | $ | 575.6 | 100.0 | % |
(a) | Reserves as of December 31, 2016 divided by annualized fourth quarter production volumes. |
(b) | Texas margin taxes and the federal income taxes associated with a corporate subsidiary have not been deducted from future production revenues in the calculation of the standardized measure as the impact of these taxes would not have a significant effect on the calculated standardized measure. |
(c) | As East Texas contains 56.4 MMBoe, or 39.0% of total proved reserves of 144.8 MMBoe, the following table presents the production, by product, for East Texas for 2016 and 2015. As we acquired our interests in East Texas during 2015, information for 2014 is not presented. |
Year Ended December 31, | ||||||
2016 | 2015 | |||||
(In thousands, except daily production) | ||||||
Oil (MBbls) | 17 | 4 | ||||
Natural gas liquids (Mgal) | 1,117 | 13 | ||||
Natural gas (MMcf) | 30,315 | 12,548 | ||||
Total (Mboe) | 5,097 | 2,096 | ||||
Average daily production (Boe per day)* | 13,926 | 13,610 |
* | Calculated using 154 days for the year ended December 31, 2015, the number of days between the closing date of the assets acquired from Anadarko E&P Onshore LLC and December 31, 2015. |
(d) | As the Piceance Basin contains 36.1 MMBoe, or 24.9% of total proved reserves of 144.8 MMBoe, the following table presents the production, by product, for the Piceance Basin for 2016, 2015 and 2014. |
Year Ended December 31, | |||||||||
2016 | 2015 | 2014 | |||||||
(In thousands, except daily production) | |||||||||
Oil (MBbls) | 52 | 46 | 23 | ||||||
Natural gas liquids (Mgal) | 22,288 | 24,448 | 12,439 | ||||||
Natural gas (MMcf) | 24,206 | 23,639 | 11,767 | ||||||
Total (Mboe) | 4,617 | 4,568 | 2,280 | ||||||
Average daily production (Boe per day)* | 12,615 | 12,515 | 10,806 |
* | Calculated using 211 days for the year ended December 31, 2014, the number of days between the closing date of the WPX Acquisition (as defined below) and December 31, 2014. |
As of December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
Reserve Data: | |||||||||||
Estimated net proved reserves: | |||||||||||
Oil (MMBbls) | 32.5 | 36.1 | 56.9 | ||||||||
Natural Gas Liquids (MMBbls) | 7.8 | 7.8 | 12.4 | ||||||||
Natural Gas (Bcf) | 627.0 | 721.6 | 418.0 | ||||||||
Total (MMBoe) | 144.8 | 164.2 | 139.0 | ||||||||
Proved developed reserves (MMBoe) | 139.2 | 161.7 | 126.4 | ||||||||
Proved undeveloped reserves (MMBoe) | 5.6 | 2.5 | 12.6 | ||||||||
Proved developed reserves as a percentage of total proved reserves | 96 | % | 98 | % | 91 | % | |||||
Standardized measure (in millions)(a) | $ | 575.6 | $ | 694.9 | $ | 1,754.6 | |||||
Oil and Natural Gas Prices(b) | |||||||||||
Oil - WTI per Bbl | $ | 39.25 | $ | 46.79 | $ | 91.48 | |||||
Natural gas - Henry Hub per MMBtu | $ | 2.48 | $ | 2.59 | $ | 4.35 |
(a) | Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with assumptions required by the FASB and the SEC (using current costs and the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price) without giving effect to non-property related expenses such as general administrative expenses and debt service or to depletion, depreciation and amortization and discounted using an annual discount rate of 10%. For the purpose of calculating the standardized measure, the costs and prices are unescalated. Federal income taxes have not been deducted from future production revenues in the calculation of standardized measure as each partner is separately taxed on its share of Legacy's taxable income. In addition, Texas margin taxes and the federal income taxes associated with a corporate subsidiary have not been deducted from future production revenues in the calculation of the standardized measure as the impact of these taxes would not have a significant effect on the calculated standardized measure. Standardized measure does not give effect to derivative transactions. For a description of our derivative transactions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Investing Activities.” Oil and natural gas prices as of each date are based on the unweighted arithmetic average of the first-day-of-the-month price for each month as posted by Plains Marketing L.P. and Platts Gas Daily for oil and natural gas, respectively, with these representative prices adjusted by property to arrive at the appropriate net sales price, which is held constant over the economic life of the property. |
(b) | Oil and natural gas prices as of each date are based on the unweighted arithmetic average of the first day of the month price for each month as posted by Plains Marketing L.P. and Platts Gas Daily for oil and natural gas, respectively, with these representative prices adjusted by property to arrive at the appropriate net sales price, which is held constant over the economic life of the property. |
Year Ended December 31, | |||||||||||
2016 | 2015(a) | 2014(b) | |||||||||
Production: | |||||||||||
Oil (MBbls) | 4,019 | 4,608 | 4,784 | ||||||||
Natural gas liquids (MGal) | 36,757 | 42,210 | 30,861 | ||||||||
Gas (MMcf) | 66,824 | 50,687 | 25,936 | ||||||||
Total (MBoe) | 16,032 | 14,061 | 9,841 | ||||||||
Average daily production (Boe per day) | 43,803 | 38,523 | 26,962 | ||||||||
Average sales price per unit (excluding commodity derivative cash settlements): | |||||||||||
Oil (per Bbl) | $ | 37.95 | $ | 43.37 | $ | 82.94 | |||||
NGL (per Gal) | $ | 0.42 | $ | 0.39 | $ | 0.89 | |||||
Gas (per Mcf) | $ | 2.19 | $ | 2.41 | $ | 4.17 | |||||
Combined (per Boe) | $ | 19.61 | $ | 24.09 | $ | 54.09 | |||||
Average sales price per unit (including commodity derivative cash settlements): | |||||||||||
Oil (per Bbl) | $ | 47.27 | $ | 63.32 | $ | 81.80 | |||||
NGL (per Gal) | $ | 0.42 | $ | 0.39 | $ | 0.89 | |||||
Gas (per Mcf) | $ | 2.60 | $ | 3.22 | $ | 4.48 | |||||
Combined (per Boe) | $ | 23.63 | $ | 33.55 | $ | 54.36 | |||||
Average unit costs per Boe: | |||||||||||
Production costs, excluding production and other taxes | $ | 10.59 | $ | 13.03 | $ | 18.98 | |||||
Ad valorem taxes | $ | 0.60 | $ | 0.81 | $ | 1.22 | |||||
Production and other taxes | $ | 0.89 | $ | 1.17 | $ | 3.20 | |||||
General and administrative | $ | 2.72 | $ | 3.31 | $ | 3.96 | |||||
Depletion, depreciation and amortization | $ | 9.38 | $ | 12.61 | $ | 17.65 |
(a) | Reflects the production and operating results of the properties acquired as a part of our acquisition of both 100% of the issued and outstanding limited liability company membership interests in Dew Gathering LLC from WGR Operating LP and various oil and natural gas properties and associated exploration and production assets from Anadarko E&P Onshore LLC (collectively, the "Anadarko Acquisitions") from the closing date on July 31, 2015 through December 31, 2015. |
(b) | Reflects the production and operating results of the WPX Acquisition properties from the closing date on June 4, 2014 through December 31, 2014. |
Oil | Natural Gas | Total | |||||||||||||||
Gross | Net | Gross | Net | Gross | Net | ||||||||||||
Operated | 2,478 | 1,856 | 1,321 | 1,157 | 3,799 | 3,013 | |||||||||||
Non-operated | 2,782 | 269 | 4,194 | 1,233 | 6,976 | 1,502 | |||||||||||
Total | 5,260 | 2,125 | 5,515 | 2,390 | 10,775 | 4,515 |
Developed Acreage(a) | Undeveloped Acreage(b) | Total Acreage | |||||||||
Gross(c) | Net(d) | Gross(c) | Net(d) | Gross(c) | Net(d) | ||||||
Total | 1,039,876 | 511,675 | 181,912 | 52,214 | 1,221,788 | 563,889 |
(a) | Developed acres are acres spaced or assigned to productive wells or wells capable of production. |
(b) | Undeveloped acres include acres held by production but not currently allocated or assigned to producing wells or wells capable of production and acres not held by production and subject to the primary term of the leases, regardless of whether such acreage contains proved reserves. The majority of our proved undeveloped locations are located on acreage currently held by production. As the economic viability of any potential oil and natural gas development related to the acres not held by production is remote, we have assigned minimal value to our acreage not held by production and thus the minimum remaining term of those leases is immaterial to us. |
(c) | A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest. |
(d) | A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the product of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof. |
Year Ended December 31, | ||||||||
2016 | 2015 | 2014 | ||||||
Gross: | ||||||||
Development | ||||||||
Productive | 12 | 14 | 122 | |||||
Dry | — | — | — | |||||
Total | 12 | 14 | 122 | |||||
Exploratory | ||||||||
Productive | — | — | — | |||||
Dry | — | — | — | |||||
Total | — | — | — | |||||
Net: | ||||||||
Development | ||||||||
Productive | 2.2 | 3.8 | 41.1 | |||||
Dry | — | — | — | |||||
Total | 2.2 | 3.8 | 41.1 | |||||
Exploratory | ||||||||
Productive | — | — | — | |||||
Dry | — | — | — | |||||
Total | — | — | — |
ITEM 3. | LEGAL PROCEEDINGS |
ITEM 4. | MINE SAFETY DISCLOSURES |
ITEM 5. | MARKET FOR REGISTRANT’S UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Price Ranges | Cash Distribution | Cash Distribution | |||||||||||||
2016 | High | Low | per Unit | to General Partner | |||||||||||
First Quarter | $ | 1.96 | $ | 0.61 | $ | — | $ | — | |||||||
Second Quarter | $ | 3.89 | $ | 0.78 | $ | — | $ | — | |||||||
Third Quarter | $ | 2.01 | $ | 1.25 | $ | — | $ | — | |||||||
Fourth Quarter | $ | 2.74 | $ | 1.13 | $ | — | $ | — | |||||||
Price Ranges | Cash Distribution | Cash Distribution | |||||||||||||
2015 | High | Low | per Unit | to General Partner | |||||||||||
First Quarter | $ | 15.55 | $ | 8.06 | $ | 0.350 | $ | 6,409 | |||||||
Second Quarter | $ | 14.40 | $ | 8.43 | $ | 0.350 | $ | 6,409 | |||||||
Third Quarter | $ | 10.49 | $ | 3.70 | $ | 0.150 | $ | 2,747 | |||||||
Fourth Quarter | $ | 6.12 | $ | 1.04 | $ | — | $ | — |
ITEM 6. | SELECTED FINANCIAL DATA |
Years Ended December 31, | |||||||||||||||||||
2016 | 2015(a) | 2014(b) | 2013 | 2012(c) | |||||||||||||||
(In thousands, except per unit data) | |||||||||||||||||||
Statement of Operations Data: | |||||||||||||||||||
Revenues: | |||||||||||||||||||
Oil sales | $ | 152,507 | $ | 199,841 | $ | 396,774 | $ | 405,536 | $ | 286,254 | |||||||||
Natural gas liquids sales | 15,406 | 16,645 | 27,483 | 14,095 | 14,592 | ||||||||||||||
Natural gas sales | 146,444 | 122,293 | 108,042 | 65,858 | 45,614 | ||||||||||||||
Total revenues | 314,357 | 338,779 | 532,299 | 485,489 | 346,460 | ||||||||||||||
Expenses: | |||||||||||||||||||
Oil and natural gas production | 179,333 | 194,491 | 198,801 | 154,679 | 112,951 | ||||||||||||||
Production and other taxes | 14,267 | 16,383 | 31,534 | 29,508 | 20,778 | ||||||||||||||
General and administrative | 43,639 | 46,511 | 38,980 | 28,907 | 24,526 | ||||||||||||||
Depletion, depreciation, amortization | |||||||||||||||||||
and accretion | 150,414 | 177,258 | 173,686 | 158,415 | 102,144 | ||||||||||||||
Impairment of long-lived assets | 61,796 | 633,805 | 448,714 | 85,757 | 37,066 | ||||||||||||||
(Gain) loss on disposal of assets | (50,095 | ) | (3,972 | ) | (2,479 | ) | 579 | (2,496 | ) | ||||||||||
Total expenses | 399,354 | 1,064,476 | 889,236 | 457,845 | 294,969 | ||||||||||||||
Operating income (loss) | (84,997 | ) | (725,697 | ) | (356,937 | ) | 27,644 | 51,491 | |||||||||||
Other income (expense): | |||||||||||||||||||
Interest income | 67 | 329 | 873 | 776 | 16 | ||||||||||||||
Interest expense | (79,060 | ) | (76,891 | ) | (67,218 | ) | (50,089 | ) | (20,260 | ) | |||||||||
Gain on extinguishment of debt | 150,802 | — | — | — | — | ||||||||||||||
Equity in income of equity method investees | — | 126 | 428 | 559 | 111 | ||||||||||||||
Net gains (losses) on commodity derivatives | (41,224 | ) | 98,253 | 138,092 | (13,531 | ) | 38,493 | ||||||||||||
Other | (179 | ) | 841 | 258 | 18 | (118 | ) | ||||||||||||
Income (loss) before income taxes | (54,591 | ) | (703,039 | ) | (284,504 | ) | (34,623 | ) | 69,733 | ||||||||||
Income tax (expense) benefit | (1,229 | ) | 1,498 | 859 | (649 | ) | (1,096 | ) | |||||||||||
Net income (loss) | (55,820 | ) | (701,541 | ) | (283,645 | ) | (35,272 | ) | 68,637 | ||||||||||
Distributions to preferred unitholders | (19,000 | ) | (19,000 | ) | (11,694 | ) | — | — | |||||||||||
Net income (loss) attributable to unitholders | $ | (74,820 | ) | $ | (720,541 | ) | $ | (295,339 | ) | $ | (35,272 | ) | $ | 68,637 |
Years Ended December 31, | |||||||||||||||||||
2016 | 2015(a) | 2014(b) | 2013 | 2012(c) | |||||||||||||||
(In thousands, except per unit data) | |||||||||||||||||||
Income (loss) per unit | |||||||||||||||||||
Basic and diluted | $ | (1.06 | ) | $ | (10.45 | ) | $ | (4.92 | ) | $ | (0.62 | ) | $ | 1.40 | |||||
Distributions paid per unit | $ | — | $ | 1.46 | $ | 2.41 | $ | 2.31 | $ | 2.23 |
Cash Flow Data: | |||||||||||||||||||
Net cash provided by (used in) operating activities | $ | (310 | ) | $ | 2,046 | $ | 207,216 | $ | 241,134 | $ | 149,641 | ||||||||
Net cash provided by (used in) | |||||||||||||||||||
investing activities | $ | 119,989 | $ | (377,420 | ) | $ | (632,414 | ) | $ | (209,401 | ) | $ | (696,279 | ) | |||||
Net cash provided by (used in) | |||||||||||||||||||
financing activities | $ | (119,130 | ) | $ | 376,655 | $ | 423,339 | $ | (32,658 | ) | $ | 546,996 | |||||||
Capital expenditures | $ | 41,932 | $ | 579,463 | $ | 640,414 | $ | 204,911 | $ | 704,191 |
Historical As of December 31, | |||||||||||||||||||
2016 | 2015(a) | 2014(b) | 2013 | 2012(c) | |||||||||||||||
(In thousands) | |||||||||||||||||||
Balance Sheet Data | |||||||||||||||||||
Cash and cash equivalents | $ | 2,555 | $ | 2,006 | $ | 725 | $ | 2,584 | $ | 3,509 | |||||||||
Other current assets | 80,217 | 127,453 | 191,529 | 72,115 | 84,401 | ||||||||||||||
Oil and natural gas properties, net of | |||||||||||||||||||
accumulated depletion, depreciation, | |||||||||||||||||||
amortization and impairment | 1,181,909 | 1,408,956 | 1,639,974 | 1,535,429 | 1,571,926 | ||||||||||||||
Other assets | 35,145 | 74,705 | 66,378 | 49,705 | 30,163 | ||||||||||||||
Total assets | $ | 1,299,826 | $ | 1,613,120 | $ | 1,898,606 | $ | 1,659,833 | $ | 1,689,999 | |||||||||
Current liabilities | $ | 86,609 | $ | 81,093 | $ | 97,576 | $ | 93,890 | $ | 103,723 | |||||||||
Long-term debt | 1,161,394 | 1,427,614 | 938,876 | 878,693 | 775,838 | ||||||||||||||
Other long-term liabilities | 273,902 | 284,090 | 224,949 | 176,854 | 140,158 | ||||||||||||||
Partners’ equity (deficit) | (222,079 | ) | (179,677 | ) | 637,205 | 510,396 | 670,280 | ||||||||||||
Total liabilities and partners’ equity (deficit) | $ | 1,299,826 | $ | 1,613,120 | $ | 1,898,606 | $ | 1,659,833 | $ | 1,689,999 |
(a) | Reflects Legacy’s purchase of the oil and natural gas properties acquired in the Anadarko Acquisitions as of the closing date of the acquisition on July 31, 2015. Consequently, the operations of these acquired properties are only included for the period from the closing date of the acquisition through December 31, 2015 and thereafter. |
(b) | Reflects Legacy’s purchase of the oil and natural gas properties acquired in the WPX Acquisition as of the closing date of the acquisition on June 4, 2014. Consequently, the operations of these acquired properties are only included for the period from the closing date of the acquisition through December 31, 2014 and thereafter. |
(c) | Reflects Legacy’s purchase of the oil and natural gas properties located primarily in the Permian Basin from a subsidiary of Concho Resources, Inc. (the "COG 2012 Acquisition") as of the date of the acquisition. Consequently, the operations of these acquired properties are only included for the period from the closing date of the acquisition on December 20, 2012 through December 31, 2012 and thereafter. |
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Year Ended December 31, | |||||||||||
2016 | 2015(b) | 2014(c) | |||||||||
(In thousands, except per unit data and production) | |||||||||||
Revenues | |||||||||||
Oil sales | $ | 152,507 | $ | 199,841 | $ | 396,774 | |||||
Natural gas liquids sales | 15,406 | 16,645 | 27,483 | ||||||||
Natural gas sales | 146,444 | 122,293 | 108,042 | ||||||||
Total revenues | $ | 314,357 | $ | 338,779 | $ | 532,299 | |||||
Expenses: | |||||||||||
Oil and natural gas production | $ | 169,755 | $ | 183,163 | $ | 186,750 | |||||
Ad valorem taxes | 9,578 | 11,328 | 12,051 | ||||||||
Total | $ | 179,333 | $ | 194,491 | $ | 198,801 | |||||
Production and other taxes | $ | 14,267 | $ | 16,383 | $ | 31,534 | |||||
General and administrative, excluding transaction related costs and LTIP | $ | 31,196 | $ | 30,919 | $ | 29,760 | |||||
Transaction related costs | 5,245 | 8,919 | 5,425 | ||||||||
LTIP expense | 7,198 | 6,673 | 3,795 | ||||||||
Total general and administrative | $ | 43,639 | $ | 46,511 | $ | 38,980 | |||||
Depletion, depreciation, amortization and accretion | $ | 150,414 | $ | 177,258 | $ | 173,686 | |||||
Commodity derivative cash settlements: | |||||||||||
Oil derivative cash settlements received (paid) | 37,464 | 91,953 | (5,431 | ) | |||||||
Natural gas derivative cash settlements received | 27,041 | 40,972 | 8,097 | ||||||||
Total commodity derivative cash settlements | 64,505 | 132,925 | 2,666 | ||||||||
Production: | |||||||||||
Oil (MBbls) | 4,019 | 4,608 | 4,784 | ||||||||
Natural gas liquids (MGal) | 36,757 | 42,210 | 30,861 | ||||||||
Natural gas (MMcf) | 66,824 | 50,687 | 25,936 | ||||||||
Total (MBoe) | 16,032 | 14,061 | 9,841 | ||||||||
Average daily production (Boe/d) | 43,803 | 38,523 | 26,962 | ||||||||
Average sales price per unit (excluding commodity derivative cash settlements): | |||||||||||
Oil price (per Bbl) | $ | 37.95 | $ | 43.37 | $ | 82.94 | |||||
Natural gas liquids price (per Gal) | $ | 0.42 | $ | 0.39 | $ | 0.89 | |||||
Natural gas price (per Mcf)(a) | $ | 2.19 | $ | 2.41 | $ | 4.17 | |||||
Combined (per Boe) | $ | 19.61 | $ | 24.09 | $ | 54.09 | |||||
Average sales price per unit (including commodity derivative cash settlements): | |||||||||||
Oil price (per Bbl) | $ | 47.27 | $ | 63.32 | $ | 81.80 | |||||
Natural gas liquids price (per Gal) | $ | 0.42 | $ | 0.39 | $ | 0.89 | |||||
Natural gas price (per Mcf)(a) | $ | 2.60 | $ | 3.22 | $ | 4.48 | |||||
Combined (per Boe) | $ | 23.63 | $ | 33.55 | $ | 54.36 | |||||
Average WTI oil spot price (per Bbl) | $ | 43.29 | $ | 48.66 | $ | 93.17 | |||||
Average Henry Hub natural gas spot price (per MMBtu) | $ | 2.52 | $ | 2.62 | $ | 4.37 | |||||
Average unit costs per Boe: | |||||||||||
Production costs, excluding production and other taxes | $ | 10.59 | $ | 13.03 | $ | 18.98 | |||||
Ad valorem taxes | $ | 0.60 | $ | 0.81 | $ | 1.22 | |||||
Production and other taxes | $ | 0.89 | $ | 1.17 | $ | 3.20 | |||||
General and administrative, excluding acquisition costs and LTIP | $ | 1.95 | $ | 2.20 | $ | 3.02 | |||||
Total general and administrative | $ | 2.72 | $ | 3.31 | $ | 3.96 | |||||
Depletion, depreciation, amortization and accretion | $ | 9.38 | $ | 12.61 | $ | 17.65 |
(a) | We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content contained within those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, our realized natural gas prices in the Permian Basin and for Legacy as a whole are higher than Henry Hub natural gas index prices due to this NGL content. |
(b) | Reflects the production and operating results of the oil and natural gas properties acquired in the Anadarko Acquisitions from the closing date of the acquisition on July 31, 2015 through December 31, 2015. |
(c) | Reflects the production and operating results of the oil and natural gas properties acquired in the WPX Acquisition from the closing date of the acquisition on June 4, 2014 through December 31, 2014 and thereafter. |
• | Interest expense; |
• | (Gain) loss on extinguishment of debt; |
• | Income tax expense (benefit); |
• | Depletion, depreciation, amortization and accretion; |
• | Impairment of long-lived assets; |
• | (Gain) loss on sale of partnership investment; |
• | (Gain) loss on disposal of assets; |
• | Equity in (income) loss of equity method investees; |
• | Unit-based compensation expense (benefit) related to LTIP unit awards accounted for under the equity or liability methods; |
• | Minimum payments received in excess of overriding royalty interest earned; |
• | Equity in EBITDA of equity method investee; |
• | Net (gains) losses on commodity derivatives; |
• | Net cash settlements received (paid) on commodity derivatives; and |
• | Transaction related expenses. |
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Net loss | $ | (55,820 | ) | $ | (701,541 | ) | $ | (283,645 | ) | ||
Plus: | |||||||||||
Interest expense | 79,060 | 76,891 | 67,218 | ||||||||
Gain on extinguishment of debt | (150,802 | ) | — | — | |||||||
Income tax expense (benefit) | 1,229 | (1,498 | ) | (859 | ) | ||||||
Depletion, depreciation, amortization and accretion | 150,414 | 177,258 | 173,686 | ||||||||
Impairment of long-lived assets | 61,796 | 633,805 | 448,714 | ||||||||
Gain on disposal of assets | (50,095 | ) | (3,972 | ) | (2,479 | ) | |||||
Equity in income of equity method investees | — | (126 | ) | (428 | ) | ||||||
Unit-based compensation expense | 7,198 | 6,673 | 3,795 | ||||||||
Minimum payments received in excess of overriding royalty interest earned(a) | 1,659 | 1,130 | 1,381 | ||||||||
Equity in EBITDA of equity method investee(b) | — | 169 | 805 | ||||||||
Net (gains) losses on commodity derivatives | 41,224 | (98,253 | ) | (138,092 | ) | ||||||
Net cash settlements received (paid) on commodity derivatives | 64,505 | 132,925 | 2,666 | ||||||||
Transaction related expenses | 5,245 | 8,919 | 5,425 | ||||||||
Adjusted EBITDA | $ | 155,613 | $ | 232,380 | $ | 278,187 |
(a) | A portion of minimum payments received in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the minimum payments are recognized in net income. |
(b) | EBITDA applicable to equity method investee is defined as the equity method investee's net income plus interest expense and depreciation. We divested our interest in this investee in May of 2015. |
Calendar Year | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | ||||||
2017 | 182,500 | $84.75 | $84.75 | ||||||
2018 | 730,000 | $55.04 | $55.00 | - | $55.15 |
Average | Price Range per | ||||||||
Calendar Year | Volumes (MMBtu) | Price per MMBtu | MMBtu | ||||||
2017 | 27,600,000 | $3.36 | $3.29 | - | $3.39 | ||||
2018 | 42,200,000 | $3.25 | $3.04 | - | $3.39 | ||||
2019 | 25,800,000 | $3.36 | $3.29 | - | $3.39 |
Time Period | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | |||||
2017 | 2,190,000 | $(0.30) | $(0.75) | - | $(0.05) | |||
2018 | 1,460,000 | $(1.25) | $(1.25) |
Average Long | Average Short | |||||
Time Period | Volumes (Bbls) | Put Price per Bbl | Call Price per Bbl | |||
2017 | 2,190,000 | $45.00 | $59.02 | |||
2018 | 1,551,250 | $47.06 | $60.29 |
Average Short Put | Average Long Put | Average Short Call | ||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | ||||
2017 | 72,400 | $60.00 | $85.00 | $104.20 |
Average Long Put | Average Short Put | Average Swap | ||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | ||||
2017 | 182,500 | $57.00 | $82.00 | $90.85 | ||||
2018 | 127,750 | $57.00 | $82.00 | $90.50 |
Average Long Put | Average Short Call | |||||
Time Period | Volumes (MMBtu) | Price per MMBtu | Price per MMBtu | |||
2017 | 14,600,000 | $2.90 | $3.44 |
Volumes | Average Short Put | Average Long Put | Average Short Call | |||||
Calendar Year | (MMBtu) | Price per MMBtu | Price per MMBtu | Price per MMBtu | ||||
2017 | 5,040,000 | $3.75 | $4.25 | $5.53 |
2017 | ||||
Average | ||||
Volumes (MMBtu) | Price per MMBtu | |||
NWPL | 7,300,000 | $(0.16) | ||
SoCal | 2,500,250 | $0.11 | ||
San Juan | 2,500,250 | $(0.10) |
• | with respect to ABR loans, the alternate base rate equals the highest of the prime rate, the Federal funds effective rate plus 0.50%, or the one-month London Interbank Offered Rate (“LIBOR”) plus 1.00%, plus an applicable margin ranging from and including 1.00% to 2.00% per annum, determined by the percentage of the borrowing base then in effect that is utilized, provided, that if the ratio of our first lien debt as of the last day of any fiscal quarter to our EBITDA (as defined in the Current Credit Agreement) for the four fiscal quarters ending on such day is greater than 3.00 to 1.00, then the applicable margin shall be increased by 0.50% during the next succeeding fiscal quarter, or |
• | with respect to any Eurodollar loans, one-, two-, three- or six-month LIBOR plus an applicable margin ranging from and including 2.00% to 3.00% per annum, determined by the percentage of the borrowing base then in effect that is utilized. |
• | incur indebtedness; |
• | enter into certain leases; |
• | grant certain liens; |
• | enter into certain derivatives; |
• | make certain loans, acquisitions, capital expenditures and investments; |
• | make distributions; |
• | merge, consolidate or allow any material change in the character of our business; |
• | repurchase Senior Notes or repay second lien loans; |
• | engage in certain asset dispositions, including a sale of all or substantially all of our assets; or |
• | maintain a consolidated cash balance in excess of $20 million without prepaying the loans in an amount equal to such excess. |
• | first lien debt to EBITDA for the four fiscal quarters ending on last day of the fiscal quarter immediately preceding the date of determination for which financial statements are available to not be greater than: (i) 3.50 to 1.00, at any time during the period from and including February 19, 2016 through December 31, 2016, (ii) 3.25 to 1.00, at any time during the fiscal quarter ending March 31, 2017, (iii) 3.00 to 1.00, at any time during the fiscal quarter ending June 30, 2017 and (iv) 2.50 to 1.00, at any time on or after July 1, 2017; |
• | secured debt to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter immediately preceding the date of determination to not be greater than 4.50 to 1.00 beginning with the fiscal quarter ending December 31, 2018; |
• | as of the last day of any fiscal quarter, total EBITDA over the last four quarters to total Interest Expense over the last four quarters to be greater than 2.00 to 1.00; |
• | consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under ASC 815, which includes the current portion of oil, natural gas and interest rate derivatives; |
• | as of the last day of any fiscal quarter beginning with the fiscal quarter ending June 30, 2017, the ratio of (a) the sum of (i) the net present value using NYMEX forward pricing, discounted at 10 percent per annum, of Legacy’s proved developed producing oil and gas properties (“PDP PV-10”), as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be, beginning with the reserve report to be delivered on July 1, 2017 (giving pro forma effect to material acquisitions or dispositions since the date of such reports), (ii) the net mark to market value of our swap agreements and (iii) our cash and cash equivalents to (b) Secured Debt to not be equal to or less than 1.00 to 1.00 . |
• | failure to pay any principal when due or any reimbursement amount, interest, fees or other amount within certain grace periods; |
• | a representation or warranty is proven to be incorrect when made; |
• | failure to perform or otherwise comply with the covenants or conditions contained in the Current Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods; |
• | default by us on the payment of any other indebtedness in excess of $15.0 million, or any event occurs that permits or causes the acceleration of the indebtedness; |
• | bankruptcy or insolvency events involving us or any of our subsidiaries; |
• | the loan documents cease to be in full force and effect; |
• | our failing to create a valid lien, except in limited circumstances; |
• | a change of control, which will occur upon (i) the acquisition by any person or group of persons of beneficial ownership of more than 35% of the aggregate ordinary voting power of our equity securities, (ii) the first day on which a majority of the members of the board of directors of our general partner are not continuing directors (which is generally defined to mean members of our board of directors as of April 1, 2014 and persons who are nominated for election or elected to our general partner’s board of directors with the approval of a majority of the continuing directors who were members of such board of directors at the time of such nomination or election), (iii) the direct or indirect sale, transfer or other disposition in one or a series of related transactions of all or substantially all of the properties or assets (including equity interests of subsidiaries) of us and our subsidiaries to any person, (iv) the adoption of a plan related to our liquidation or dissolution or (v) Legacy Reserves GP, LLC’s ceasing to be our sole general partner; provided that, under certain circumstances, a conversion from one form of entity to another form of entity or exchange of equity interests in another form entity shall not constitute a change in control; |
• | the entry of, and failure to pay, one or more adverse judgments in excess of $15.0 million or one or more non-monetary judgments that could reasonably be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal; |
• | specified ERISA events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $2.0 million in any year; |
• | the Intercreditor Agreement (as defined below) ceases to be in effect, except to the extent permitted by the terms thereof; and |
• | if an “Event of Default” occurs under the Second Lien Term Loan Credit Agreement (as defined below). |
• | not permit, beginning with the fiscal quarter ending June 30, 2017, the ratio of the sum of (i) PDP PV-10, (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents to Secured Debt to be less than 1.0 to 1.0; |
• | not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, Legacy’s ratio of Secured Debt as of such day to EBITDA for the four fiscal quarters then ending to be greater than 4.50 to 1.00; |
• | within a certain period of time after the date of the Second Lien Term Loan Credit Agreement, enter into hedging transactions covering at least 75% of the projected oil and natural gas production from Proved Developed Producing Properties for each month until the two year anniversary of the Second Lien Term Loan Credit Agreement; |
• | Legacy is required to mortgage 95% of the total value of all of its Oil and Gas Properties set forth in the most recently evaluated Reserve Report and grant a mortgage on certain identified undeveloped acreage in the Permian Basin; and |
• | require us to grant a perfected security interest in its cash and securities accounts, subject to certain customary exceptions. |
Year | Percentage | ||
2016 | 104.000 | % | |
2017 | 102.000 | % | |
2018 | 100.000 | % |
Year | Percentage | ||
2017 | 103.313 | % | |
2018 | 101.656 | % | |
2019 and thereafter | 100.000 | % |
Obligations Due in Period | |||||||||||||||||||
Contractual Cash Obligations | 2017 | 2018-2019 | 2020-2021 | Thereafter | Total | ||||||||||||||
(In thousands) | |||||||||||||||||||
Long-term debt | |||||||||||||||||||
Revolving credit facility(a) | $ | — | $ | 463,000 | $ | — | $ | — | $ | 463,000 | |||||||||
Interest on revolving credit facility(b) | 18,103 | 22,629 | — | — | 40,732 | ||||||||||||||
Second Lien Term Loans | — | — | 60,000 | — | 60,000 | ||||||||||||||
Interest on Second Lien Term Loans | 7,200 | 14,400 | 4,800 | — | 26,400 | ||||||||||||||
Senior Notes | — | — | 665,645 | — | 665,645 | ||||||||||||||
Interest on Senior Notes | 47,303 | 94,605 | 57,692 | — | 199,600 | ||||||||||||||
Derivative obligations(c) | 3,429 | — | — | — | 3,429 | ||||||||||||||
Management compensation(d) | 2,155 | 4,310 | 4,310 | — | 10,775 | ||||||||||||||
Employee compensation(e) | 2,011 | 2,817 | — | — | 4,828 | ||||||||||||||
Asset retirement obligation(f) | 2,980 | 5,960 | 5,960 | 257,248 | 272,148 | ||||||||||||||
CO2 purchase commitment(g) | 4,751 | 17,275 | 17,553 | 9,049 | 48,628 | ||||||||||||||
Office lease | 1,477 | 2,678 | 1,024 | — | 5,179 | ||||||||||||||
Total contractual cash obligations | $ | 89,409 | $ | 627,674 | $ | 816,984 | $ | 266,297 | $ | 1,800,364 |
(a) | Represents amounts outstanding under our revolving credit facility as of December 31, 2016. |
(b) | Based upon our weighted average interest rate of 3.91% under our revolving credit facility as of December 31, 2016. |
(c) | Derivative obligations represent net liabilities for commodity and interest rate derivatives that were valued as of December 31, 2016, the ultimate settlement of which are unknown because they are subject to continuing market risk. Please read “Quantitative and Qualitative Disclosure about Market Risk” for additional information regarding our derivative obligations. |
(d) | The related employment agreements do not contain termination provisions; therefore, the ultimate payment obligation is not known. For purposes of this table, management has not reflected payments subsequent to 2020. |
(e) | Legacy has bonus agreements with certain of its non-executive employees. The bonus agreements provide for fixed bonus amounts to be paid to employees contingent upon various criteria including their continuous employment or a change in control. |
(f) | Asset retirement obligations of oil and natural gas assets, excluding salvage value and accretion, the ultimate settlement and timing of which cannot be precisely determined in advance. |
(g) | Represents the value of the minimum volume of CO2 required to be purchased in the respective annual period. As the contract price per Mcf of CO2 is based on NYMEX WTI price on the date of purchase, we have assumed the NYMEX WTI strip price as of December 31, 2016. |
• | it requires assumptions to be made that were uncertain at the time the estimate was made, and |
• | changes in the estimate or different estimates that could have been selected could have a material impact on our consolidated results of operations or financial condition. |
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
ITEM 9A. | CONTROLS AND PROCEDURES |
• | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; |
• | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and the board of directors of our general partner; and |
• | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisitions, use or disposition of our assets that could have a material effect on our financial statements. |
ITEM 9B. | OTHER INFORMATION |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
ITEM 11. | EXECUTIVE COMPENSATION |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
Exhibit | ||
Number | Description | |
2.1 | — | Membership Interest Purchase and Sale Agreement, dated July 3, 2015, by and between Legacy Reserves Operating LP and WGR Operating LP (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on July 9, 2015, Exhibit 2.1) |
2.2 | — | Purchase and Sale Agreement, dated July 3, 2015, by and between Legacy Reserves Operating LP and Anadarko E&P Onshore LLC (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on July 9, 2015, Exhibit 2.2) |
3.1 | — | Certificate of Limited Partnership of Legacy Reserves LP (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.1) |
3.2 | — | Fourth Amended and Restated Agreement of Limited Partnership of Legacy Reserves LP, as amended by Amendment No. 1 thereto, dated May 10, 2016 (Incorporated by reference to Legacy Reserves LP's quarterly report on Form 10-Q filed on August 3, 2016, Exhibit 3.2) |
3.3 | — | Certificate of Formation of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.3) |
3.4 | — | Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 3.4) |
3.5 | — | First Amendment to Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC (Incorporated by reference to Legacy Reserves LP's quarterly report on Form 10-Q (File No. 001-33249) filed on May 4, 2012, Exhibit 3.6) |
3.6 | — | Second Amendment to Amended and Restated Limited Liability Company Agreement of Legacy Reserves GP, LLC. (Incorporated by reference to Legacy Reserves LP's quarterly report on Form 10-Q (File No. 001-33249) filed on May 4, 2012, Exhibit 3.7) |
4.1 | — | Registration Rights Agreement dated June 29, 2006, between Henry Holdings LP and Legacy Reserves LP and Legacy Reserves GP, LLC (the “Henry Registration Rights Agreement”) (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006, Exhibit 4.2) |
4.2 | — | Registration Rights Agreement dated March 15, 2006, by and among Legacy Reserves LP, Legacy Reserves GP, LLC and the other parties thereto (the “Founders Registration Rights Agreement”) (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006, Exhibit 4.3) |
4.3 | — | Indenture, dated as of December 4, 2012, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (including form of the 8% senior notes due 2020) (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed December 10, 2012, Exhibit 4.1) |
4.4 | — | Indenture, dated as of May 28, 2013, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (including form of 6.625% senior notes due 2021) (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed May 31, 2013, Exhibit 4.1) |
4.5 | — | First Supplemental Indenture, dated as of August 25, 2015, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 8% Senior Notes due 2020) (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed November 6, 2015, Exhibit 10.2) |
4.6 | — | First Supplemental Indenture, dated as of August 25, 2015, among Legacy Reserves LP, Legacy Reserves Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee (related to 6.625% Senior Notes due 2021) (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed November 6, 2015, Exhibit 10.3) |
Exhibit | ||
Number | Description | |
10.1 | — | Third Amended and Restated Credit Agreement, among Legacy Reserves LP, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, Compass Bank, as Syndication Agent, UBS Securities LLC and U.S. Bank National Association, as Co-Documentation Agents and the Lenders Party thereto, dated as of April 1, 2014 (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed April 2, 2014, Exhibit 10.1) |
10.2 | — | First Amendment to Third Amended and Restated Credit Agreement, dated April 17, 2014, by and between Legacy Reserves LP, Wells Fargo Bank, National Association, as administrative agent and certain other financial institutions party thereto as lenders (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed October 31, 2014, Exhibit 10.1) |
10.3 | — | Second Amendment to Third Amended and Restated Credit Agreement, dated May 22, 2014, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed May 28, 2014, Exhibit 10.1) |
10.4 | — | Third Amendment to Third Amended and Restated Credit Agreement, dated December 29, 2014, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 27, 2015, Exhibit 10.11) |
10.5 | — | Fourth Amendment to Third Amended and Restated Credit Agreement, dated February 23, 2015, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 27, 2015, Exhibit 10.12) |
10.6 | — | Fifth Amendment to Third Amended and Restated Credit Agreement, dated August 5, 2015, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s quarterly report on Form 10-Q (File No. 001-33249) filed August 7, 2015, Exhibit 10.2) |
10.7 | — | Sixth Amendment to Third Amended and Restated Credit Agreement, dated November 13, 2015, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 26, 2016, Exhibit 10.14) |
10.8 | — | Seventh Amendment to Third Amended and Restated Credit Agreement, dated February 19, 2016, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on February 24, 2016, Exhibit 10.1) |
10.9 | — | Eighth Amendment to Third Amended and Restated Credit Agreement, dated October 25, 2016, among Legacy Reserves LP, as borrower, the guarantors named therein, Wells Fargo Bank, National Association, as administrative agent, and the lenders signatory thereto (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed October 28, 2016, Exhibit 10.2) |
10.10 | — | Term Loan Credit Agreement, among Legacy Reserves LP, as Borrower, Cortland Capital Market Services LLC, as Administrative Agent and the lenders party thereto, dated as of October 25, 2016 (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed October 28, 2016, Exhibit 10.1) |
Exhibit | ||
Number | Description | |
10.11† | — | Amendment No. 1 to the Amended and Restated Legacy Reserves LP Long-Term Incentive Plan, dated as of June 12, 2015. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 12, 2015, Exhibit 10.1) |
10.12† | — | Amended and Restated Legacy Reserves LP Long-Term Incentive Plan effective as of August 17, 2007 (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed August 23, 2007, Exhibit 10.1) |
10.13† | — | Form of Legacy Reserves LP Long-Term Incentive Plan Restricted Unit Grant Agreement (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 10.6) |
10.14† | — | Form of Legacy Reserves LP Long-Term Incentive Plan Unit Option Grant Agreement (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006, Exhibit 10.7) |
10.15† | — | Form of Legacy Reserves LP Long-Term Incentive Plan Unit Grant Agreement (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed September 5, 2006, Exhibit 10.8) |
10.16† | — | Employment Agreement dated as of March 15, 2006, between Cary D. Brown and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333- 134056) filed May 12, 2006, Exhibit 10.9) |
10.17† | — | Section 409A Compliance Amendment to Employment Agreement dated December 31, 2008, between Cary D. Brown and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed December 31, 2008, Exhibit 10.1) |
10.18† | — | Employment Agreement dated as of March 15, 2006, between Kyle A. McGraw and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333-134056) filed May 12, 2006, Exhibit 10.11) |
10.19† | — | Section 409A Compliance Amendment to Employment Agreement dated December 31, 2008, between Kyle A. McGraw and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed December 31, 2008, Exhibit 10.3) |
10.20† | — | Employment Agreement dated as of March 15, 2006, between Paul T. Horne and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s Registration Statement on Form S-1 (File No. 333- 134056) filed May 12, 2006, Exhibit 10.12) |
10.21† | — | Section 409A Compliance Amendment to Employment Agreement dated December 31, 2008, between Paul T. Horne and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed December 31, 2008, Exhibit 10.4) |
10.22† | — | Employment Agreement effective April 1, 2012 between Micah C. Foster and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP's current report on Form 8-K (File No. 001-33249) filed April 25, 2012, Exhibit 10.1) |
10.23† | — | Employment Agreement effective May 1, 2012 between Dan G. LeRoy and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP's quarterly report on Form 10-Q (File No. 001-33249) filed August 3, 2012, Exhibit 10.3) |
10.24† | — | Employment Agreement effective September 24, 2012 between James Daniel Westcott and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP's quarterly report on Form 10-Q (File No. 001-33249) filed October 31, 2012, Exhibit 10.1) |
10.25† | — | Non-Executive Chairman Agreement by and among Legacy Reserves GP, LLC, Legacy Reserves Services, Inc. and Cary D. Brown, dated as of February 3, 2015. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on February 6, 2015, Exhibit 10.1) |
Exhibit | ||
Number | Description | |
10.26† | — | Employment Agreement effective as of March 1, 2015, between Kyle M. Hammond and Legacy Reserves Services, Inc. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on February 27, 2015, Exhibit 10.1) |
10.27† | — | Second Amendment to Employment Agreement effective as of March 1, 2015, between Legacy Reserves Services, Inc., Paul T. Horne and Legacy Reserves GP, LLC. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on February 27, 2015, Exhibit 10.2) |
10.28† | — | Second Amendment to Employment Agreement effective as of March 1, 2015, between Legacy Reserves Services, Inc., Kyle A. McGraw and Legacy Reserves GP, LLC. (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on February 27, 2015, Exhibit 10.3) |
10.29† | — | Form of Legacy Reserves LP Long-Term Incentive Plan Grant of Phantom Units (Objective) (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 21, 2014, Exhibit 10.25) |
10.30† | — | Form of Legacy Reserves LP Long-Term Incentive Plan Grant of Phantom Units (Subjective) (Incorporated by reference to Legacy Reserves LP's annual report on Form 10-K (File No. 001-33249) filed on February 21, 2014, Exhibit 10.26) |
10.31† | — | Form of Grant of Phantom Units Under Objective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.1) |
10.32† | — | Form of Grant of Phantom Units (Cash) Under Subjective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.2) |
10.33† | — | Form of Grant of Phantom Units (Units) Under Subjective Component of Long-Term Equity Incentive Compensation (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.3) |
10.34† | — | Form of Retention Bonus Agreement (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed on June 17, 2016, Exhibit 10.4) |
10.35† | — | Purchase and Sale Agreement, by and between WPX Energy Rocky Mountain, LLC, Legacy Reserves Operating LP, Legacy Reserves GP, LLC and Legacy Reserves LP (schedules omitted pursuant to Item 601(b)(2) of Regulation S-K), dated May 2, 2014 (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed May 6, 2014, Exhibit 2.1) |
10.36† | — | IDR Holders Agreement, dated June 4, 2014, by and between Legacy Reserves LP and WPX Rocky Mountain, LLC (Incorporated by reference to Legacy Reserves LP’s current report on Form 8-K (File No. 001-33249) filed June 4, 2014, Exhibit 10.1) |
21.1* | — | List of subsidiaries of Legacy Reserves LP |
23.1* | — | Consent of BDO USA, LLP |
23.2* | — | Consent of LaRoche Petroleum Consultants, Ltd. |
31.1* | — | Rule 13a-14(a) Certification of CEO (under Section 302 of the Sarbanes-Oxley Act of 2002) |
31.2* | — | Rule 13a-14(a) Certification of CFO (under Section 302 of the Sarbanes-Oxley Act of 2002) |
32.1* | — | Section 1350 Certifications (under Section 906 of the Sarbanes-Oxley Act of 2002) |
99.1* | — | Summary Reserve Report from LaRoche Petroleum Consultants, Ltd. |
101.INS* | — | XBRL Instance Document |
101.SCH* | — | XBRL Taxonomy Extension Schema Document |
101.DEF* | — | XBRL Taxonomy Extension Definition Linkbase Document |
101.PRE* | — | XBRL Taxonomy Extension Presentation Linkbase Document |
101.CAL* | — | XBRL Taxonomy Extension Calculation Linkbase Document |
101.LAB* | — | XBRL Taxonomy Extension Label Linkbase Document |
* | Filed herewith | |
† | Management contract or compensatory plan or arrangement |
ITEM 16. | FORM 10-K SUMMARY |
LEGACY RESERVES LP | |||
By: | LEGACY RESERVES GP, LLC, | ||
its general partner | |||
By: | /S/ JAMES DANIEL WESTCOTT | ||
Name: | James Daniel Westcott | ||
Title: | Executive Vice President and Chief Financial Officer (Principal Financial Officer) | ||
Signature | Title | Date | ||
/S/ PAUL T. HORNE | Chairman of the Board, President and Chief Executive Officer | February 22, 2017 | ||
Paul T. Horne | (Principal Executive Officer) | |||
/S/ JAMES DANIEL WESTCOTT | Executive Vice President and Chief Financial Officer | February 22, 2017 | ||
James Daniel Westcott | (Principal Financial Officer) | |||
/S/ MICAH C. FOSTER | Chief Accounting Officer and Controller | February 22, 2017 | ||
Micah C. Foster | (Principal Accounting Officer) | |||
/S/ KYLE A. MCGRAW | Executive Vice President, Chief Development Officer and Director | February 22, 2017 | ||
Kyle A. McGraw | ||||
/S/ CARY D. BROWN | Director | February 22, 2017 | ||
Cary D. Brown | ||||
/S/ DALE A. BROWN | Director | February 22, 2017 | ||
Dale A. Brown | ||||
/S/ WILLIAM R. GRANBERRY | Director | February 22, 2017 | ||
William R. Granberry | ||||
/S/ G. LARRY LAWRENCE | Director | February 22, 2017 | ||
G. Larry Lawrence | ||||
/S/ WILLIAM D. SULLIVAN | Director | February 22, 2017 | ||
William D. Sullivan | ||||
/S/ KYLE D. VANN | Director | February 22, 2017 | ||
Kyle D. Vann | ||||
/S/ D. DWIGHT SCOTT | Director | February 22, 2017 | ||
D. Dwight Scott |
Page | |
Report of Independent Registered Public Accounting Firm | |
Consolidated Financial Statements: | |
Consolidated Balance Sheets — December 31, 2016 and 2015 | |
Consolidated Statements of Operations — Years Ended December 31, 2016, 2015 and 2014 | |
Consolidated Statements of Unitholders’ Equity — Years Ended December 31, 2016, 2015 and 2014 | |
Consolidated Statements of Cash Flows — Years Ended December 31, 2016, 2015 and 2014 | |
Notes to Consolidated Financial Statements | |
Unaudited Supplementary Information |
/s/ BDO USA, LLP |
2016 | 2015 | ||||||
(In thousands) | |||||||
ASSETS | |||||||
Current assets: | |||||||
Cash | $ | 2,555 | $ | 2,006 | |||
Accounts receivable, net: | |||||||
Oil and natural gas | 43,192 | 33,944 | |||||
Joint interest owners | 23,414 | 25,378 | |||||
Other | 2 | 86 | |||||
Fair value of derivatives (Notes 8 and 9) | 6,162 | 63,711 | |||||
Prepaid expenses and other current assets | 7,447 | 4,334 | |||||
Total current assets | 82,772 | 129,459 | |||||
Oil and natural gas properties, at cost: | |||||||
Proved oil and natural gas properties using the successful efforts method of accounting | 3,305,856 | 3,485,634 | |||||
Unproved properties | 13,448 | 13,424 | |||||
Accumulated depletion, depreciation, amortization and impairment | (2,137,395 | ) | (2,090,102 | ) | |||
Total oil and natural gas properties, net | 1,181,909 | 1,408,956 | |||||
Other property and equipment, net of accumulated depreciation and amortization of $10,412 and $8,915, respectively | 3,423 | 4,575 | |||||
Operating rights, net of amortization of $5,369 and $4,953, respectively | 1,648 | 2,064 | |||||
Fair value of derivatives (Notes 8 and 9) | 20,553 | 56,373 | |||||
Other assets | 8,874 | 11,047 | |||||
Investments in equity method investees | 647 | 646 | |||||
Total assets | $ | 1,299,826 | $ | 1,613,120 | |||
LIABILITIES AND PARTNERS’ DEFICIT | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 9,092 | $ | 13,581 | |||
Accrued oil and natural gas liabilities (Note 1) | 53,248 | 50,573 | |||||
Fair value of derivatives (Notes 8 and 9) | 9,743 | 2,019 | |||||
Asset retirement obligation (Note 11) | 2,980 | 3,496 | |||||
Other (Notes 8 and 13) | 11,546 | 11,424 | |||||
Total current liabilities | 86,609 | 81,093 | |||||
Long-term debt (Note 3) | 1,161,394 | 1,427,614 | |||||
Asset retirement obligation (Note 11) | 269,168 | 282,909 | |||||
Fair value of derivatives (Notes 8 and 9) | 4,091 | — | |||||
Other long-term liabilities | 643 | 1,181 | |||||
Total liabilities | 1,521,905 | 1,792,797 | |||||
Commitments and contingencies (Note 6) | |||||||
Partners’ equity (deficit): | |||||||
Series A Preferred equity - 2,300,000 units issued and outstanding at December 31, 2016 and December 31, 2015 | 55,192 | 55,192 | |||||
Series B Preferred equity - 7,200,000 units issued and outstanding at December 31, 2016 and December 31, 2015 | 174,261 | 174,261 | |||||
Incentive distribution equity - 100,000 units issued and outstanding at December 31, 2016 and December 31, 2015 | 30,814 | 30,814 | |||||
Limited partners' deficit - 72,056,097 and 68,949,961 units issued and outstanding at December 31, 2016 and 2015, respectively | (482,200 | ) | (439,811 | ) | |||
General partner’s deficit (approximately 0.03%) | (146 | ) | (133 | ) | |||
Total partners’ deficit | (222,079 | ) | (179,677 | ) | |||
Total liabilities and partners’ deficit | $ | 1,299,826 | $ | 1,613,120 |
2016 | 2015 | 2014 | |||||||||
(In thousands, except per unit data) | |||||||||||
Revenues: | |||||||||||
Oil sales | $ | 152,507 | $ | 199,841 | $ | 396,774 | |||||
Natural gas liquids (NGL) sales | 15,406 | 16,645 | 27,483 | ||||||||
Natural gas sales | 146,444 | 122,293 | 108,042 | ||||||||
Total revenues | 314,357 | 338,779 | 532,299 | ||||||||
Expenses: | |||||||||||
Oil and natural gas production | 179,333 | 194,491 | 198,801 | ||||||||
Production and other taxes | 14,267 | 16,383 | 31,534 | ||||||||
General and administrative | 43,639 | 46,511 | 38,980 | ||||||||
Depletion, depreciation, amortization and accretion | 150,414 | 177,258 | 173,686 | ||||||||
Impairment of long-lived assets | 61,796 | 633,805 | 448,714 | ||||||||
Gain on disposal of assets | (50,095 | ) | (3,972 | ) | (2,479 | ) | |||||
Total expenses | 399,354 | 1,064,476 | 889,236 | ||||||||
Operating loss | (84,997 | ) | (725,697 | ) | (356,937 | ) | |||||
Other income (expense): | |||||||||||
Interest income | 67 | 329 | 873 | ||||||||
Interest expense (Notes 3, 8 and 9) | (79,060 | ) | (76,891 | ) | (67,218 | ) | |||||
Gain on extinguishment of debt | 150,802 | — | — | ||||||||
Equity in income of equity method investees | — | 126 | 428 | ||||||||
Net gains (losses) on commodity derivatives (Notes 8 and 9) | (41,224 | ) | 98,253 | 138,092 | |||||||
Other | (179 | ) | 841 | 258 | |||||||
Loss before income taxes | (54,591 | ) | (703,039 | ) | (284,504 | ) | |||||
Income tax (expense) benefit | (1,229 | ) | 1,498 | 859 | |||||||
Net loss | $ | (55,820 | ) | $ | (701,541 | ) | $ | (283,645 | ) | ||
Distributions to preferred unitholders | (19,000 | ) | (19,000 | ) | (11,694 | ) | |||||
Net loss attributable to unitholders | $ | (74,820 | ) | $ | (720,541 | ) | $ | (295,339 | ) | ||
Loss per unit — basic and diluted (Note 12) | $ | (1.06 | ) | $ | (10.45 | ) | $ | (4.92 | ) | ||
Weighted average number of units used in | |||||||||||
computing loss per unit — | |||||||||||
Basic and Diluted | 70,605 | 68,928 | 60,053 |
Series A Preferred Equity | Series B Preferred Equity | Incentive Distribution Equity | Unitholders' Equity (Deficit) | |||||||||||||||||||||||||||||||||
Units | Amount | Units | Amount | Units | Amount | Limited Partner Units | Limited Partner Amount | General Partner Amount | Total Partners' Equity (Deficit) | |||||||||||||||||||||||||||
(In thousands) | ||||||||||||||||||||||||||||||||||||
Balance, December 31, 2013 | — | $ | — | — | $ | — | — | $ | — | 57,280 | $ | 510,322 | $ | 74 | $ | 510,396 | ||||||||||||||||||||
Units issued to Legacy Board of Directors for services | — | — | — | — | — | — | 18 | 499 | — | 499 | ||||||||||||||||||||||||||
Issuance of preferred units, net | 2,300 | 55,192 | 7,200 | 174,261 | — | — | — | — | — | 229,453 | ||||||||||||||||||||||||||
Unit-based compensation | — | — | — | — | — | — | — | 3,797 | — | 3,797 | ||||||||||||||||||||||||||
Vesting of restricted and phantom units | — | — | — | — | — | — | 113 | — | — | — | ||||||||||||||||||||||||||
Issuance of units, net | — | — | — | — | — | — | 11,500 | 303,457 | — | 303,457 | ||||||||||||||||||||||||||
Incentive Distribution Units issued in exchange for oil and natural gas properties | — | — | — | — | 100 | 30,814 | — | — | — | 30,814 | ||||||||||||||||||||||||||
Distributions to preferred unitholders | — | — | — | — | — | — | — | (11,694 | ) | — | (11,694 | ) | ||||||||||||||||||||||||
Distributions to unitholders, $2.405 per unit | — | — | — | — | — | — | — | (145,872 | ) | — | (145,872 | ) | ||||||||||||||||||||||||
Net loss | — | — | — | — | — | — | — | (283,624 | ) | (21 | ) | (283,645 | ) | |||||||||||||||||||||||
Balance, December 31, 2014 | 2,300 | 55,192 | 7,200 | 174,261 | 100 | 30,814 | 68,911 | 376,885 | 53 | 637,205 | ||||||||||||||||||||||||||
Units issued to Legacy Board of Directors for services | — | — | — | — | — | — | 66 | 604 | — | 604 | ||||||||||||||||||||||||||
Unit-based compensation | — | — | — | — | — | — | — | 5,858 | — | 5,858 | ||||||||||||||||||||||||||
Vesting of restricted and phantom units | — | — | — | — | — | — | 78 | — | — | — | ||||||||||||||||||||||||||
Issuance of units, net | — | — | — | — | — | — | — | (103 | ) | — | (103 | ) | ||||||||||||||||||||||||
Incentive Distribution Units issued in exchange for oil and natural gas properties | — | — | — | — | — | — | (105 | ) | (1,349 | ) | — | (1,349 | ) | |||||||||||||||||||||||
Distributions to preferred unitholders | — | — | — | — | — | — | — | (19,000 | ) | — | (19,000 | ) | ||||||||||||||||||||||||
Distributions to unitholders, $1.46 per unit | — | — | — | — | — | — | — | (101,351 | ) | — | (101,351 | ) | ||||||||||||||||||||||||
Net loss | — | — | — | — | — | — | — | (701,355 | ) | (186 | ) | (701,541 | ) | |||||||||||||||||||||||
Balance, December 31, 2015 | 2,300 | 55,192 | 7,200 | 174,261 | 100 | 30,814 | 68,950 | (439,811 | ) | (133 | ) | (179,677 | ) | |||||||||||||||||||||||
Units issued to Legacy Board of Directors for services | — | — | — | — | — | — | 237 | 614 | — | 614 | ||||||||||||||||||||||||||
Unit-based compensation | — | — | — | — | — | — | — | 6,252 | — | 6,252 | ||||||||||||||||||||||||||
Vesting of restricted and phantom units | — | — | — | — | — | — | 150 | — | — | — | ||||||||||||||||||||||||||
Units issued in exchange for retirement of debt | — | — | — | — | — | — | 2,719 | 6,607 | — | 6,607 | ||||||||||||||||||||||||||
Distributions to unitholders | — | — | — | — | — | — | — | (55 | ) | — | (55 | ) | ||||||||||||||||||||||||
Net loss | — | — | — | — | — | — | (55,807 | ) | (13 | ) | (55,820 | ) | ||||||||||||||||||||||||
Balance, December 31, 2016 | 2,300 | $ | 55,192 | 7,200 | $ | 174,261 | 100 | $ | 30,814 | 72,056 | $ | (482,200 | ) | $ | (146 | ) | $ | (222,079 | ) |
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Cash flows from operating activities: | |||||||||||
Net loss | $ | (55,820 | ) | $ | (701,541 | ) | $ | (283,645 | ) | ||
Adjustments to reconcile net loss to net cash (used in) provided by operating activities: | |||||||||||
Depletion, depreciation, amortization and accretion | 150,414 | 177,258 | 173,686 | ||||||||
Amortization of debt discount and issuance costs | 10,319 | 5,532 | 4,637 | ||||||||
Gain on extinguishment of debt | (150,802 | ) | — | — | |||||||
Impairment of long-lived assets | 61,796 | 633,805 | 448,714 | ||||||||
(Gain) loss on derivatives | 40,679 | (99,971 | ) | (140,771 | ) | ||||||
Equity in income of equity method investees | — | (126 | ) | (428 | ) | ||||||
Distribution from equity method investee | — | 191 | 1,467 | ||||||||
Unit-based compensation | 7,035 | 6,451 | 2,089 | ||||||||
Gain on disposal of assets | (50,095 | ) | (3,972 | ) | (2,479 | ) | |||||
Changes in assets and liabilities: | |||||||||||
(Increase) decrease in accounts receivable, oil and natural gas | (9,248 | ) | 15,447 | (1,962 | ) | ||||||
(Increase) decrease in accounts receivable, joint interest owners | 1,964 | (9,143 | ) | 297 | |||||||
Decrease in accounts receivable, other | 84 | 151 | 389 | ||||||||
(Increase) decrease in other assets | (940 | ) | 333 | (1,193 | ) | ||||||
Increase (decrease) in accounts payable | (4,489 | ) | 10,794 | (3,228 | ) | ||||||
Increase (decrease) in accrued oil and natural gas liabilities | 2,675 | (28,042 | ) | 15,454 | |||||||
Decrease in other liabilities | (3,882 | ) | (5,121 | ) | (5,811 | ) | |||||
Total adjustments | 55,510 | 703,587 | 490,861 | ||||||||
Net cash (used in) provided by operating activities | (310 | ) | 2,046 | 207,216 | |||||||
Cash flows from investing activities: | |||||||||||
Investment in oil and natural gas properties | (41,496 | ) | (577,186 | ) | (638,942 | ) | |||||
Proceeds from sale of assets | 97,416 | 69,118 | 5,334 | ||||||||
Investment in other equipment | (436 | ) | (2,277 | ) | (1,472 | ) | |||||
Net cash settlements on commodity derivatives | 64,505 | 132,925 | 2,666 | ||||||||
Net cash provided by (used in) investing activities | 119,989 | (377,420 | ) | (632,414 | ) | ||||||
Cash flows from financing activities: | |||||||||||
Proceeds from long-term debt | 266,000 | 840,000 | 1,333,000 | ||||||||
Payments of long-term debt | (376,402 | ) | (341,000 | ) | (1,275,000 | ) | |||||
Payments of debt issuance costs | (8,728 | ) | (1,891 | ) | (10,005 | ) | |||||
Proceeds from issuance of limited partner interests, net | — | (103 | ) | 532,910 | |||||||
Distributions to unitholders | — | (120,351 | ) | (157,566 | ) | ||||||
Net cash (used in) provided by financing activities | (119,130 | ) | 376,655 | 423,339 | |||||||
Net increase (decrease) in cash | 549 | 1,281 | (1,859 | ) | |||||||
Cash, beginning of period | 2,006 | 725 | 2,584 | ||||||||
Cash, end of period | $ | 2,555 | $ | 2,006 | $ | 725 | |||||
Non-Cash Investing and Financing Activities: | |||||||||||
Asset retirement obligation costs and liabilities | $ | 1 | $ | 92 | $ | 941 | |||||
Asset retirement obligations associated with property acquisitions | $ | 24 | $ | 60,526 | $ | 50,487 | |||||
Asset retirement obligations associated with properties sold | $ | (24,605 | ) | $ | (9,386 | ) | $ | (5,891 | ) | ||
Units acquired in exchange for investment in equity method investee | $ | — | $ | (1,349 | ) | $ | — | ||||
Units issued in exchange for Senior Notes | $ | 6,607 | $ | — | $ | — | |||||
Incentive Distribution units issued in exchange for oil and natural gas properties | $ | — | $ | — | $ | 30,814 |
• | Right to receive distributions of available cash within 45 days after the end of each quarter. |
• | No limited partner shall have any management power over our business and affairs; the general partner shall conduct, direct and manage LRLP’s activities. |
• | The general partner may be removed if such removal is approved by the unitholders holding at least 66 2/3 percent of the outstanding units, including units held by LRLP’s general partner and its affiliates. |
• | Right to receive information reasonably required for tax reporting purposes within 90 days after the close of the calendar year. |
December 31, | |||||||
2016 | 2015 | ||||||
(In thousands) | |||||||
Revenue payable to joint interest owners | $ | 19,576 | $ | 15,253 | |||
Accrued lease operating expense | 17,696 | 19,007 | |||||
Accrued capital expenditures | 7,019 | 2,881 | |||||
Accrued ad valorem tax | 5,300 | 8,723 | |||||
Other | 3,657 | 4,709 | |||||
$ | 53,248 | $ | 50,573 |
December 31, | ||||||||
2016 | 2015 | |||||||
(In thousands) | ||||||||
Credit Facility due 2019 | $ | 463,000 | $ | 608,000 | ||||
Second Lien Term Loans due 2020 | 60,000 | — | ||||||
8% Senior Notes due 2020 | 232,989 | 300,000 | ||||||
6.625% Senior Notes due 2021 | 432,656 | 550,000 | ||||||
1,188,645 | 1,458,000 | |||||||
Unamortized discount on Second Lien Term Loans and Senior Notes | (12,802 | ) | (17,604 | ) | ||||
Unamortized debt issuance costs (a) | (14,449 | ) | (12,782 | ) | ||||
Total long term debt | $ | 1,161,394 | $ | 1,427,614 |
(a) | In order to comply with Accounting Standards Update No. 2015-03, unamortized debt issuance costs are now recorded as a direct deduction from the carrying amount of debt. As such, debt issuance costs have been reclassified from other assets to long-term debt on a retrospective basis. This reclassification had no impact on historical income from continuing operations or retained earnings. |
• | not permit, beginning with the fiscal quarter ending June 30, 2017, the ratio of the sum of (i) PDP PV-10, (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents to Secured Debt to be less than 1.00 to 1.00; |
• | not permit, as of the last day of any fiscal quarter beginning with the fiscal quarter ending December 31, 2018, Legacy’s ratio of Secured Debt as of such day to EBITDA for the four fiscal quarters then ending to be greater than 4.50 to 1.00; |
• | within a certain period of time after the date of the Second Lien Term Loan Credit Agreement, enter into hedging transactions covering at least 75% of the projected oil and natural gas production from Proved Developed Producing Properties for each month until the two year anniversary of the Second Lien Term Loan Credit Agreement; |
• | Legacy is required to mortgage 95% of the total value of all of its Oil and Gas Properties set forth in the most recently evaluated Reserve Report and grant a mortgage on certain identified undeveloped acreage in the Permian Basin; and |
• | require us to grant a perfected security interest in its cash and securities accounts, subject to certain customary exceptions. |
Year | Percentage | ||
2016 | 104.000 | % | |
2017 | 102.000 | % | |
2018 | 100.000 | % |
Year | Percentage | ||
2017 | 103.313 | % | |
2018 | 101.656 | % | |
2019 and thereafter | 100.000 | % |
Proved oil and natural gas properties including related equipment | $ | 422,739 | |
Future abandonment costs | (62,748 | ) | |
Fair value of net assets acquired | $ | 359,991 |
Proved oil and natural gas properties including related equipment | $ | 461,306 | |
Future abandonment costs | (27,351 | ) | |
Fair value of net assets acquired | $ | 433,955 |
Year Ended December 31, | |||||||
2015 | 2014 | ||||||
(In thousands) | |||||||
Revenues | $ | 380,619 | $ | 687,829 | |||
Net loss attributable to unitholders | $ | (713,364 | ) | $ | (243,197 | ) | |
Loss per unit — basic and diluted | $ | (10.35 | ) | $ | (4.05 | ) | |
Units used in computing loss per unit: | |||||||
Basic | 68,928 | 60,053 | |||||
Diluted | 68,928 | 60,053 |
Year Ended December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
WPX Acquisition | (In thousands) | |||||||||||
Revenues | $ | 62,522 | $ | 69,504 | $ | 48,470 | ||||||
Excess of revenues over direct operating expenses | $ | 23,622 | $ | 22,324 | $ | 22,333 | ||||||
Anadarko Acquisitions | ||||||||||||
Revenues | $ | 51,177 | $ | 22,881 | $ | — | ||||||
Excess of revenues over direct operating expenses | $ | 23,319 | $ | 12,373 | $ | — |
Level 1: | Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Legacy considers active markets as 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: | Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that Legacy values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity price swaps and collars and interest rate swaps as well as long-term incentive plan liabilities calculated using the Black-Scholes model to estimate the fair value as of the measurement date. |
Level 3: | Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e. supported by little or no market activity). Legacy’s valuation models are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 instruments currently are limited to Midland-Cushing crude oil differential swaps. Although Legacy utilizes third party broker quotes to assess the reasonableness of its prices and valuation techniques, Legacy does not have sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. |
Fair Value Measurements Using | ||||||||||||||||
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | Total Carrying | |||||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | Value as of | ||||||||||||
(In thousands) | ||||||||||||||||
LTIP liability(a) | $ | — | $ | (224 | ) | $ | — | $ | (224 | ) | ||||||
Oil and natural gas derivatives | — | 12,690 | 8 | 12,698 | ||||||||||||
Interest rate swaps | — | 183 | — | 183 | ||||||||||||
Total as of December 31, 2016 | $ | — | $ | 12,649 | $ | 8 | $ | 12,657 | ||||||||
LTIP liability(a) | $ | — | $ | — | $ | — | $ | — | ||||||||
Oil and natural gas derivatives | — | 122,920 | (4,493 | ) | 118,427 | |||||||||||
Interest rate swaps | — | (362 | ) | — | (362 | ) | ||||||||||
Total as of December 31, 2015 | $ | — | $ | 122,558 | $ | (4,493 | ) | $ | 118,065 |
(a) | See Note 13 for further discussion on unit-based compensation expenses related to the LTIP liability for certain grants accounted for under the liability method and included in other current liabilities in the accompanying consolidated balance sheet. |
Significant Unobservable Inputs (Level 3) | ||||||||||||
December 31, | ||||||||||||
2016 | 2015 | 2014 | ||||||||||
(In thousands) | ||||||||||||
Beginning balance | $ | (4,493 | ) | $ | 555 | $ | 20,615 | |||||
Total gains (losses) | 253 | (10,029 | ) | (6,185 | ) | |||||||
Settlements | 4,248 | 4,981 | 677 | |||||||||
Transfers | — | — | (14,552 | ) | (a) | |||||||
Ending balance | $ | 8 | $ | (4,493 | ) | $ | 555 | |||||
Gains included in earnings relating to derivatives | ||||||||||||
still held as of December 31, 2016, 2015 and 2014 | $ | 68 | $ | (4,493 | ) | $ | 555 |
(a) | During 2014, as part of a routine review of accounting policies and practices, Legacy reviewed the assumptions and inputs used to value its derivative instruments and determined the material inputs (such as quoted market prices and oil and natural gas volatility) for its commodity derivatives more accurately correlate to the description of Level 2 instruments. As such, all instruments previously classified as Level 3 (oil and natural gas collars, swaptions and natural gas swaps for those derivatives indexed to the West Texas Waha, ANR-Oklahoma and CIG Indices) with the exception of our Midland-Cushing crude oil differential swaps were transferred to Level 2 instruments. |
Quoted Prices in Active Markets for Identical Assets | Significant Other Observable Inputs | Significant Unobservable Inputs | ||||||||||
Description | (Level 1) | (Level 2) | (Level 3) | |||||||||
(In thousands) | ||||||||||||
2016 | ||||||||||||
Impairment(a) | $ | — | $ | — | $ | 60,729 | ||||||
Acquisitions(b) | $ | — | $ | — | $ | 11,998 | ||||||
2015 | ||||||||||||
Impairment(a) | $ | — | $ | — | $ | 385,506 | ||||||
Acquisitions(b) | $ | — | $ | — | $ | 540,347 |
(a) | Legacy periodically reviews oil and natural gas properties for impairment when facts and circumstances indicate that their carrying value may not be recoverable. During the year ended December 31, 2016, Legacy incurred impairment charges of $61.8 million as oil and natural gas properties with a net cost basis of $122.5 million were written down to their fair value of $60.7 million. During the year ended December 31, 2015, Legacy incurred impairment charges of $598.1 million as oil and natural gas properties with a net cost basis of $983.6 million were written down to their fair value of $385.5 million. In order to determine whether the carrying value of an asset is recoverable, Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If the net capitalized cost exceeds the undiscounted future net cash flows, Legacy writes the net cost basis down to the discounted future net cash flows, which is management's estimate of fair value. Significant inputs used to determine the fair value 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 underlying |
(b) | Legacy records the fair value of assets and liabilities acquired in business combinations. During the year ended December 31, 2016, Legacy acquired oil and natural gas properties with a fair value of $12.0 million in 3 immaterial transactions, both individually and in the aggregate. During the year ended December 31, 2015, Legacy acquired oil and natural gas properties with a fair value of $540.3 million in the Anadarko Acquisitions and 6 immaterial transactions, both individually and in the aggregate. Properties acquired are recorded at fair value, which correlates to the discounted future net cash flow. Significant inputs used to determine the fair value 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 underlying commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For acquired unproved properties, the market-based weighted average cost of capital rate is subjected to additional project specific risking factors. The inputs used by management for the fair value measurements of these acquired oil and natural gas properties include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. |
December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Beginning fair value of commodity derivatives | $ | 118,427 | $ | 153,099 | $ | 17,673 | |||||
Total gain (loss) crude oil derivatives | (9,410 | ) | 25,715 | 101,813 | |||||||
Total gain (loss) natural gas derivatives | (31,814 | ) | 72,538 | 36,279 | |||||||
Crude oil derivative cash settlements paid (received) | (37,464 | ) | (91,953 | ) | 5,431 | ||||||
Natural gas derivative cash settlements received | (27,041 | ) | (40,972 | ) | (8,097 | ) | |||||
Ending fair value of commodity derivatives | $ | 12,698 | $ | 118,427 | $ | 153,099 |
December 31, 2016 | ||||||||||||
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | ||||||||||
Offsetting Derivative Assets: | (In thousands) | |||||||||||
Commodity derivatives | $ | 56,103 | $ | (30,648 | ) | $ | 25,455 | |||||
Interest rate derivatives | 1,328 | (68 | ) | 1,260 | ||||||||
Total derivative assets | $ | 57,431 | $ | (30,716 | ) | $ | 26,715 | |||||
Offsetting Derivative Liabilities: | ||||||||||||
Commodity derivatives | $ | (43,405 | ) | $ | 30,648 | $ | (12,757 | ) | ||||
Interest rate derivatives | (1,145 | ) | 68 | (1,077 | ) | |||||||
Total derivative liabilities | $ | (44,550 | ) | $ | 30,716 | $ | (13,834 | ) | ||||
December 31, 2015 | ||||||||||||
Gross Amounts of Recognized Assets | Gross Amounts Offset in the Consolidated Balance Sheets | Net Amounts Presented in the Consolidated Balance Sheets | ||||||||||
Offsetting Derivative Assets: | (In thousands) | |||||||||||
Commodity derivatives | $ | 177,082 | $ | (58,655 | ) | $ | 118,427 | |||||
Interest rate derivatives | 1,982 | (325 | ) | 1,657 | ||||||||
Total derivative assets | $ | 179,064 | $ | (58,980 | ) | $ | 120,084 | |||||
Offsetting Derivative Liabilities: | ||||||||||||
Commodity derivatives | $ | (58,655 | ) | $ | 58,655 | $ | — | |||||
Interest rate derivatives | (2,344 | ) | 325 | (2,019 | ) | |||||||
Total derivative liabilities | $ | (60,999 | ) | $ | 58,980 | $ | (2,019 | ) |
Calendar Year | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | |||||
2017 | 182,500 | $84.75 | $84.75 | |||||
2018 | 730,000 | $55.04 | $55.00 | - | $55.15 |
Time Period | Volumes (Bbls) | Average Price per Bbl | Price Range per Bbl | |||||
2017 | 2,190,000 | $(0.30) | $(0.75) | - | $(0.05) |
Average Long | Average Short | |||||
Time Period | Volumes (Bbls) | Put Price per Bbl | Call Price per Bbl | |||
2017 | 2,190,000 | $45.00 | $59.02 | |||
2018 | 1,095,000 | $45.83 | $59.97 |
Average Short Put | Average Long Put | Average Short Call | ||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | ||||
2017 | 72,400 | $60.00 | $85.00 | $104.20 |
Average Long Put | Average Short Put | Average Swap | ||||||
Calendar Year | Volumes (Bbls) | Price per Bbl | Price per Bbl | Price per Bbl | ||||
2017 | 182,500 | $57.00 | $82.00 | $90.85 | ||||
2018 | 127,750 | $57.00 | $82.00 | $90.50 |
Average | Price Range | |||||||
Calendar Year | Volumes (MMBtu) | Price per MMBtu | per MMBtu | |||||
2017 | 27,600,000 | $3.36 | $3.29 | - | $3.39 | |||
2018 | 42,200,000 | $3.25 | $3.04 | - | $3.39 | |||
2019 | 25,800,000 | $3.36 | $3.29 | - | $3.39 |
Average Long Put | Average Short Call | |||||
Time Period | Volumes (MMBtu) | Price per MMBtu | Price per MMBtu | |||
2017 | 14,600,000 | $2.90 | $3.44 |
Average Short Put | Average Long Put | Average Short Call | ||||||
Calendar Year | Volumes (MMBtu) | Price per MMBtu | Price per MMBtu | Price per MMBtu | ||||
2017 | 5,040,000 | $3.75 | $4.25 | $5.53 |
2017 | ||||
Average | ||||
Volumes (MMBtu) | Price per MMBtu | |||
NWPL | 7,300,000 | $(0.16) | ||
SoCal | 2,500,250 | $0.11 | ||
San Juan | 2,500,250 | $(0.10) |
December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Beginning fair value of interest rate swaps | $ | (362 | ) | $ | (2,080 | ) | $ | (4,759 | ) | ||
Total loss on interest rate swaps | (2,108 | ) | (1,548 | ) | (551 | ) | |||||
Cash settlements paid | 2,653 | 3,266 | 3,230 | ||||||||
Ending fair value of interest rate swaps | $ | 183 | $ | (362 | ) | $ | (2,080 | ) |
Weighted Average Fixed | Effective | Maturity | Estimated Fair Market Value at December 31, | ||||||||
Notional Amount | Rate | Date | Date | 2016 | |||||||
(Dollars in thousands) | |||||||||||
$115,000 | 0.850 | % | 9/1/2015 | 9/1/2017 | (11 | ) | |||||
$235,000 | 1.363 | % | 9/1/2015 | 9/1/2019 | 194 | ||||||
Total fair value of interest rate derivatives | $ | 183 |
2016 | 2015 | 2014 | |||
Enterprise (Teppco) Crude Oil, LP | 1% | 6% | 12% | ||
Plains Marketing, LP | 6% | 7% | 10% |
December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Asset retirement obligation — beginning of period | $ | 286,405 | $ | 226,525 | $ | 175,786 | |||||
Liabilities incurred with properties acquired | 24 | 60,526 | 50,487 | ||||||||
Liabilities incurred with properties drilled | 1 | 92 | 941 | ||||||||
Liabilities settled during the period | (2,351 | ) | (2,615 | ) | (2,918 | ) | |||||
Liabilities associated with properties sold | (24,605 | ) | (9,386 | ) | (5,891 | ) | |||||
Current period accretion | 12,674 | 11,263 | 8,120 | ||||||||
Asset retirement obligation — end of period | $ | 272,148 | $ | 286,405 | $ | 226,525 |
Years Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Net loss | $ | (55,820 | ) | $ | (701,541 | ) | $ | (283,645 | ) | ||
Distributions to preferred unitholders | (19,000 | ) | (19,000 | ) | (11,694 | ) | |||||
Net loss attributable to unitholders | $ | (74,820 | ) | $ | (720,541 | ) | $ | (295,339 | ) | ||
Weighted average number of units outstanding | 70,605 | 68,928 | 60,053 | ||||||||
Effect of dilutive securities: | |||||||||||
Restricted and phantom units | — | — | — | ||||||||
Weighted average units and potential units outstanding | 70,605 | 68,928 | 60,053 | ||||||||
Basic and diluted loss per unit | $ | (1.06 | ) | $ | (10.45 | ) | $ | (4.92 | ) |
Units | Weighted-Average Exercise Price | Weighted-Average Remaining Contractual Term | Aggregate Intrinsic Value | |||||||||
Outstanding at January 1, 2014 | 627,043 | $ | 25.99 | |||||||||
Granted | 243,274 | $ | 28.21 | |||||||||
Exercised | (137,252 | ) | $ | 24.35 | ||||||||
Forfeited | (61,836 | ) | $ | 27.27 | ||||||||
Outstanding at December 31, 2014 | 671,229 | $ | 26.97 | 5.15 | $ | — | ||||||
UARs exercisable at | ||||||||||||
December 31, 2014 | 220,056 | $ | 25.50 | 3.51 | $ | — | ||||||
Outstanding at January 1, 2015 | 671,229 | $ | 26.97 | |||||||||
Granted | 301,020 | $ | 6.49 | |||||||||
Forfeited | (36,133 | ) | $ | 21.07 | ||||||||
Outstanding at December 31, 2015 | 936,116 | $ | 20.61 | 4.91 | $ | — | ||||||
UARs exercisable at | ||||||||||||
December 31, 2015 | 372,049 | $ | 26.45 | 3.28 | $ | — | ||||||
Outstanding at January 1, 2016 | 936,116 | $ | 20.61 | |||||||||
Expired | (21,067 | ) | $ | 16.07 | ||||||||
Forfeited | (30,503 | ) | $ | 19.80 | ||||||||
Outstanding at December 31, 2016 | 884,546 | $ | 20.75 | 3.68 | $ | — | ||||||
UARs exercisable at | ||||||||||||
December 31, 2016 | 570,369 | $ | 24.38 | 2.77 | $ | — |
Non-Vested UARs | ||||||
Number of Units | Weighted- Average Exercise Price | |||||
Non-vested at January 1, 2016 | 566,067 | $ | 16.80 | |||
Vested | (221,387 | ) | 20.14 | |||
Forfeited | (30,503 | ) | 19.80 | |||
Non-vested at December 31, 2016 | 314,177 | $ | 14.16 |
Year Ended December 31, | ||||||||
2016 | 2015 | 2014 | ||||||
Expected life (years) | 4.02 | 4.91 | 5.15 | |||||
Annual interest rate | 1.6 | % | 1.7 | % | 1.6 | % | ||
Annual distribution rate per unit | $0.00 | $0.60 | $2.44 | |||||
Volatility | 87 | % | 59 | % | 38 | % |
Year Ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Development costs | $ | 29,499 | $ | 36,934 | $ | 134,364 | |||||
Exploration costs | — | — | — | ||||||||
Acquisition costs: | |||||||||||
Proved properties | 11,998 | 598,693 | 562,649 | ||||||||
Unproved properties | 24 | 2,180 | 24,172 | ||||||||
Total acquisition, development and exploration costs | $ | 41,521 | $ | 637,807 | $ | 721,185 |
Oil (MBbls) | NGL (MBbls)(a) | Natural Gas (MMcf)(a) | Total (MBoe) | ||||||||
Total Proved Reserves: | |||||||||||
Balance, December 31, 2013 | 57,030 | 4,075 | 159,020 | 87,608 | |||||||
Purchases of minerals-in-place | 7,506 | 8,480 | 289,523 | 64,240 | |||||||
Sales of minerals-in-place | (176 | ) | — | (808 | ) | (311 | ) | ||||
Extensions and discoveries | — | — | — | — | |||||||
Revisions from drilling and recompletions | 888 | 33 | 2,594 | 1,353 | |||||||
Revisions of previous estimates due to price | (3,110 | ) | 371 | (969 | ) | (2,901 | ) | ||||
Revisions of previous estimates due to performance | (429 | ) | 149 | (5,449 | ) | (1,188 | ) | ||||
Production | (4,784 | ) | (735 | ) | (25,936 | ) | (9,842 | ) | |||
Balance, December 31, 2014 | 56,925 | 12,373 | 417,975 | 138,959 | |||||||
Purchases of minerals-in-place | 131 | 4 | 440,661 | 73,579 | |||||||
Sales of minerals-in-place | (800 | ) | (149 | ) | (59 | ) | (959 | ) | |||
Extensions and discoveries | (417 | ) | — | (540 | ) | (507 | ) | ||||
Revisions from drilling and recompletions | 904 | 2 | 1,986 | 1,237 | |||||||
Revisions of previous estimates due to price | (17,321 | ) | (2,796 | ) | (94,588 | ) | (35,880 | ) | |||
Revisions of previous estimates due to performance | 1,329 | (679 | ) | 6,885 | 1,798 | ||||||
Production | (4,608 | ) | (1,005 | ) | (50,687 | ) | (14,061 | ) | |||
Balance, December 31, 2015 | 36,143 | 7,750 | 721,633 | 164,166 | |||||||
Purchases of minerals-in-place | 13 | — | 156 | 39 | |||||||
Sales of minerals-in-place | (1,185 | ) | (40 | ) | (5,573 | ) | (2,154 | ) | |||
Revisions from ownership changes | (142 | ) | 5 | 180 | (107 | ) | |||||
Revisions from drilling and recompletions | 1,400 | — | 2,165 | 1,761 | |||||||
Revisions of previous estimates due to price | (3,358 | ) | 746 | (12,987 | ) | (4,777 | ) | ||||
Revisions of previous estimates due to performance | 3,606 | 257 | (11,730 | ) | 1,908 | ||||||
Production | (4,019 | ) | (875 | ) | (66,824 | ) | (16,032 | ) | |||
Balance, December 31, 2016 | 32,458 | 7,843 | 627,020 | 144,804 | |||||||
Proved Developed Reserves: | |||||||||||
December 31, 2013 | 48,775 | 3,870 | 139,789 | 75,943 | |||||||
December 31, 2014 | 47,203 | 12,073 | 402,802 | 126,410 | |||||||
December 31, 2015 | 34,297 | 7,729 | 718,094 | 161,708 | |||||||
December 31, 2016 | 28,092 | 7,743 | 619,959 | 139,162 | |||||||
Proved Undeveloped Reserves: | |||||||||||
December 31, 2013 | 8,255 | 205 | 19,231 | 11,665 | |||||||
December 31, 2014 | 9,722 | 300 | 15,173 | 12,551 | |||||||
December 31, 2015 | 1,846 | 21 | 3,539 | 2,457 | |||||||
December 31, 2016 | 4,366 | 100 | 7,061 | 5,642 |
(a) | We primarily report and account for our Permian Basin natural gas volumes inclusive of the NGL content in those natural gas volumes. Given the price disparity between an equivalent amount of NGLs compared to natural gas, Legacy's realized natural gas prices in the Permian Basin are substantially higher than NYMEX Henry Hub natural gas prices due to NGL content. |
December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Future production revenues | $ | 2,814,259 | $ | 3,471,519 | $ | 7,243,050 | |||||
Future costs: | |||||||||||
Production | (1,618,241 | ) | (2,015,514 | ) | (3,457,818 | ) | |||||
Development | (202,304 | ) | (205,213 | ) | (473,954 | ) | |||||
Future net cash flows before income taxes | 993,714 | 1,250,792 | 3,311,278 | ||||||||
10% annual discount for estimated timing of cash flows | (418,088 | ) | (555,851 | ) | (1,556,664 | ) | |||||
Standardized measure of discounted net cash flows | $ | 575,626 | $ | 694,941 | $ | 1,754,614 |
December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
Oil (per Bbl) (a) | $ | 39.25 | $ | 46.79 | $ | 91.48 | |||||
Natural Gas (per MMBtu) (b) | $ | 2.48 | $ | 2.59 | $ | 4.35 |
(a) | The quoted oil price for all fiscal years is the 12-month unweighted average first-day-of-the-month West Texas Intermediate price, as posted by Plains Marketing, L.P., for each month of 2016, 2015 and 2014. |
(b) | The quoted gas price for all fiscal years is the 12-month unweighted average first-day-of-the-month Henry Hub price, as posted by Platts Gas Daily, for each month of 2016, 2015 and 2014. |
Year ended December 31, | |||||||||||
2016 | 2015 | 2014 | |||||||||
(In thousands) | |||||||||||
Increase (decrease): | |||||||||||
Sales, net of production costs | $ | (120,757 | ) | $ | (127,905 | ) | $ | (301,964 | ) | ||
Net change in sales prices, net of production costs | (109,125 | ) | (1,367,523 | ) | (213,617 | ) | |||||
Changes in estimated future development costs | 99 | 9,428 | 64,273 | ||||||||
Revisions of previous estimates due to infill drilling, | |||||||||||
recompletions and stimulations | 15,632 | 24,694 | 39,228 | ||||||||
Revisions of previous quantity estimates due to performance | 57,188 | 38,083 | (39,227 | ) | |||||||
Previously estimated development costs incurred | 2,097 | 14,136 | 51,085 | ||||||||
Purchases of minerals-in-place | 294 | 218,463 | 472,057 | ||||||||
Sales of minerals-in-place | (14,781 | ) | (19,095 | ) | (2,932 | ) | |||||
Ownership interest changes | (3,886 | ) | (7,341 | ) | — | ||||||
Other | (9,028 | ) | (10,854 | ) | (26,758 | ) | |||||
Accretion of discount | 62,952 | 168,241 | 155,489 | ||||||||
Net increase (decrease) | (119,315 | ) | (1,059,673 | ) | 197,634 | ||||||
Standardized measure of discounted future net cash flows: | |||||||||||
Beginning of year | 694,941 | 1,754,614 | 1,556,980 | ||||||||
End of year | $ | 575,626 | $ | 694,941 | $ | 1,754,614 |
March 31 | June 30 | September 30 | December 31 | ||||||||||||
2016 | (In thousands, except per unit data) | ||||||||||||||
Revenues: | |||||||||||||||
Oil sales | $ | 30,320 | $ | 41,272 | $ | 38,751 | $ | 42,164 | |||||||
Natural gas liquids sales | 2,453 | 3,922 | 3,457 | 5,574 | |||||||||||
Natural gas sales | 33,086 | 28,173 | 41,332 | 43,853 | |||||||||||
Total revenues | 65,859 | 73,367 | 83,540 | 91,591 | |||||||||||
Expenses: | |||||||||||||||
Oil and natural gas production | 50,023 | 44,561 | 43,121 | 41,628 | |||||||||||
Production and other taxes | 2,573 | 3,390 | 3,986 | 4,318 | |||||||||||
General and administrative | 9,434 | 10,993 | 9,231 | 13,981 | |||||||||||
Depletion, depreciation, amortization and accretion | 36,959 | 37,668 | 36,068 | 39,719 | |||||||||||
Impairment of long-lived assets | 15,447 | — | 4,618 | 41,731 | |||||||||||
(Gain) loss on disposal of assets | (31,701 | ) | (9,141 | ) | (8,447 | ) | (806 | ) | |||||||
Total expenses | 82,735 | 87,471 | 88,577 | 140,571 | |||||||||||
Operating loss | (16,876 | ) | (14,104 | ) | (5,037 | ) | (48,980 | ) | |||||||
Interest income | 38 | 16 | — | 13 | |||||||||||
Interest expense | (25,176 | ) | (20,302 | ) | (17,080 | ) | (16,502 | ) | |||||||
Gain on extinguishment of debt | 130,804 | 19,998 | — | — | |||||||||||
Equity in income (loss) of equity method investee | (5 | ) | (9 | ) | 7 | 7 | |||||||||
Net gains (losses) on commodity derivatives | 17,038 | (37,675 | ) | 18,326 | (38,913 | ) | |||||||||
Other | (94 | ) | (98 | ) | (296 | ) | 309 | ||||||||
Loss before income taxes | 105,729 | (52,174 | ) | (4,080 | ) | (104,066 | ) | ||||||||
Income taxes | (400 | ) | (87 | ) | (223 | ) | (519 | ) | |||||||
Net income (loss) | $ | 105,329 | $ | (52,261 | ) | $ | (4,303 | ) | $ | (104,585 | ) | ||||
Distributions to preferred unitholders | (3,958 | ) | (4,750 | ) | (4,750 | ) | (5,542 | ) | |||||||
Net income (loss) attributable to unitholders | $ | 101,371 | $ | (57,011 | ) | $ | (9,053 | ) | $ | (110,127 | ) | ||||
Net income (loss) per unit — basic and diluted | $ | 1.47 | $ | (0.81 | ) | $ | (0.13 | ) | $ | (1.53 | ) | ||||
Production volumes: | |||||||||||||||
Oil (MBbl) | 1,069 | 1,039 | 962 | 949 | |||||||||||
Natural gas liquids (Mgal) | 8,241 | 9,663 | 9,742 | 9,111 | |||||||||||
Natural gas (MMcf) | 17,266 | 16,743 | 16,572 | 16,243 | |||||||||||
Total (MBoe) | 4,143 | 4,060 | 3,956 | 3,873 |
March 31 | June 30 | September 30 | December 31 | ||||||||||||
2015 | (In thousands, except per unit data) | ||||||||||||||
Revenues: | |||||||||||||||
Oil sales | $ | 50,296 | $ | 59,113 | $ | 49,779 | $ | 40,653 | |||||||
Natural gas liquids sales | 4,192 | 5,729 | 2,946 | 3,778 | |||||||||||
Natural gas sales | 27,051 | 22,959 | 36,773 | 35,510 | |||||||||||
Total revenues | 81,539 | 87,801 | 89,498 | 79,941 | |||||||||||
Expenses: | |||||||||||||||
Oil and natural gas production | 49,220 | 45,220 | 48,446 | 51,605 | |||||||||||
Production and other taxes | 4,218 | 3,986 | 4,834 | 3,345 | |||||||||||
General and administrative | 8,869 | 10,390 | 16,246 | 11,006 | |||||||||||
Depletion, depreciation, amortization and accretion | 41,068 | 36,197 | 45,041 | 54,952 | |||||||||||
Impairment of long-lived assets | 209,402 | — | 98,054 | 326,349 | |||||||||||
(Gain) loss on disposal of assets | 1,941 | (934 | ) | 560 | (5,539 | ) | |||||||||
Total expenses | 314,718 | 94,859 | 213,181 | 441,718 | |||||||||||
Operating loss | (233,179 | ) | (7,058 | ) | (123,683 | ) | (361,777 | ) | |||||||
Interest income | 206 | 176 | (55 | ) | 2 | ||||||||||
Interest expense | (17,792 | ) | (17,760 | ) | (23,351 | ) | (17,988 | ) | |||||||
Equity in income of equity method investee | 79 | 24 | (6 | ) | 29 | ||||||||||
Net gains (losses) on commodity derivatives | 20,480 | (13,497 | ) | 57,000 | 34,270 | ||||||||||
Other | 605 | 97 | 19 | 120 | |||||||||||
Loss before income taxes | $ | (229,601 | ) | $ | (38,018 | ) | $ | (90,076 | ) | $ | (345,344 | ) | |||
Income taxes | 747 | (456 | ) | (1 | ) | 1,208 | |||||||||
Net loss | $ | (228,854 | ) | $ | (38,474 | ) | $ | (90,077 | ) | $ | (344,136 | ) | |||
Distributions to preferred unitholders | $ | (4,750 | ) | $ | (4,750 | ) | $ | (4,750 | ) | $ | (4,750 | ) | |||
Net loss attributable to unitholders | $ | (233,604 | ) | $ | (43,224 | ) | $ | (94,827 | ) | $ | (348,886 | ) | |||
Net loss per unit — basic and diluted | $ | (3.39 | ) | $ | (0.63 | ) | $ | (1.38 | ) | $ | (5.06 | ) | |||
Production volumes: | |||||||||||||||
Oil (MBbl) | 1,200 | 1,171 | 1,149 | 1,088 | |||||||||||
Natural gas liquids (Mgal) | 9,686 | 11,566 | 10,084 | 10,874 | |||||||||||
Natural gas (MMcf) | 9,658 | 9,649 | 14,383 | 16,997 | |||||||||||
Total (MBoe) | 3,040 | 3,055 | 3,786 | 4,180 |
Entity | Jurisdiction of Formation | |
Binger Operations, LLC (50% non-controlling interest) | Oklahoma | |
Legacy Reserves Operating GP LLC | Delaware | |
Legacy Reserves Operating LP | Delaware | |
Legacy Reserves Services Inc. | Texas | |
Legacy Reserves Finance Corporation | Delaware | |
Dew Gathering LLC | Texas | |
Pinnacle Gas Treating LLC | Texas | |
Legacy Reserves Energy Services LLC | Texas |
LAROCHE PETROLEUM CONSULTANTS, LTD. | ||
By: | /s/ Joe A. Young | |
Name: Joe A. Young | ||
Title: Senior Partner | ||
February 22, 2017 |
1. | I have reviewed this annual report on Form 10-K of Legacy Reserves LP (the “registrant”) for the year ended December 31, 2016; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; |
(c) | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
February 22, 2017 | By: | /s/ Paul T. Horne | |
Paul T. Horne | |||
Chairman of the Board, President and Chief Executive Officer of Legacy Reserves GP, LLC, general partner of Legacy Reserves LP (Principle Executive Officer) |
1. | I have reviewed this annual report on Form 10-K of Legacy Reserves LP (the “registrant”) for the year ended December 31, 2016; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; |
(c) | Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and |
5. | The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. |
February 22, 2017 | By: | /s/ James Daniel Westcott | |
James Daniel Westcott | |||
Executive Vice President and Chief Financial Officer of Legacy Reserves GP, LLC, general partner of Legacy Reserves LP (Principal Financial Officer) |
(1) | The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership. |
/s/ Paul T. Horne | |||
Paul T. Horne | |||
Chairman of the Board, President and Chief Executive Officer | |||
February 22, 2017 | |||
/s/ James Daniel Westcott | |||
James Daniel Westcott | |||
Executive Vice President and Chief Financial Officer | |||
February 22, 2017 |
Net Reserves | Future Net Cash Flow ($) | |||||||||||||||||
Category | Oil (Barrels) | NGL (Barrels) | Gas (Mcf) | Total | Present Worth at 10% | |||||||||||||
Proved Developed | ||||||||||||||||||
Producing | 27,194,078 | 7,725,982 | 608,041,247 | $ | 862,723,108 | $ | 522,113,545 | |||||||||||
Non-Producing | 898,070 | 16,789 | 11,917,975 | 33,033,341 | 14,309,089 | |||||||||||||
Proved Undeveloped | 4,365,446 | 100,583 | 7,060,631 | 97,957,355 | 39,203,570 | |||||||||||||
Total Proved(1) | 32,457,594 | 7,843,354 | 627,019,853 | $ | 993,713,804 | $ | 575,626,204 | |||||||||||
(1) The total proved values above may or may not match those values on the total proved summary page that follows this letter due to rounding by the economics program. |
Very truly yours, | |||
LaRoche Petroleum Consultants, Ltd. | |||
State of Texas Registration Number F-1360 | |||
/s/ Joe A. Young | |||
Joe A. Young | |||
Licensed Professional Engineer | |||
State of Texas No. 62866 |
Document and Entity Information - USD ($) $ in Millions |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Feb. 21, 2017 |
Jun. 30, 2016 |
|
Document and Entity Information [Abstract] | |||
Entity Registrant Name | LEGACY RESERVES LP | ||
Entity Central Index Key | 0001358831 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Large Accelerated Filer | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2016 | ||
Document Fiscal Year Focus | 2016 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
Entity Common Stock, Shares Outstanding | 72,625,147 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Public Float | $ 117.3 |
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands |
12 Months Ended | |
---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Other property and equipment, accumulated depreciation and amortization | $ 10,412 | $ 8,915 |
Operating rights, amortization | $ 5,369 | $ 4,953 |
Limited partners' equity, units issued (in shares) | 72,056,097 | 68,949,961 |
Limited partners' equity, units outstanding (in shares) | 72,056,097 | 68,949,961 |
General partner's equity, percent | 0.03% | 0.03% |
Incentive Distribution Equity | ||
Incentive distribution equity, units issued (in shares) | 100,000 | 100,000 |
Incentive distribution equity, units outstanding (in shares) | 100,000 | 100,000 |
Series A Preferred Equity | ||
Preferred equity, units issued (in shares) | 2,300,000 | 2,300,000 |
Preferred equity, units outstanding (in shares) | 2,300,000 | 2,300,000 |
Series B Preferred Equity | ||
Preferred equity, units issued (in shares) | 7,200,000 | 7,200,000 |
Preferred equity, units outstanding (in shares) | 7,200,000 | 7,200,000 |
Consolidated Statements of Unitholders Equity (Parenthetical) - $ / shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Statement of Partners' Capital [Abstract] | |||
Distributions to unitholders (in dollars per share) | $ 0 | $ 1.46 | $ 2.405 |
Summary of Significant Accounting Policies |
12 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Significant Accounting Policies | Summary of Significant Accounting Policies (a) Organization, Basis of Presentation and Description of Business Legacy Reserves LP (“LRLP,” “Legacy” or the “Partnership”) and its affiliated entities are referred to as Legacy in these financial statements. LRLP, a Delaware limited partnership, was formed by its general partner, Legacy Reserves GP, LLC (“LRGPLLC”), on October 26, 2005 to own and operate oil and natural gas properties. LRGPLLC is a Delaware limited liability company formed on October 26, 2005, and it currently owns an approximately 0.03% general partner interest in LRLP. Significant information regarding rights of the unitholders includes the following:
In the event of a liquidation, after making required payments to Legacy's preferred unitholders, all property and cash in excess of that required to discharge all liabilities will be distributed to the unitholders and LRLP’s general partner in proportion to their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of Legacy’s assets in liquidation. Legacy owns and operates oil and natural gas producing properties located primarily in East Texas, the Permian Basin (West Texas and Southeast New Mexico), Rocky Mountain and Mid-Continent regions of the United States. Legacy has acquired oil and natural gas producing properties and drilled and undrilled leasehold. The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. (b) Accounts Receivable Accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 10). (c) Oil and Natural Gas Properties Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities. Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 11, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates. Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation. Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties 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 underlying commodity prices embedded in Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the year ended December 31, 2016, Legacy recognized $61.8 million of impairment expense in 43 separate producing fields, due primarily to well performance and the further decline in commodity prices during the year ended December 31, 2016, which decreased the expected future cash flows below the carrying value of the assets. For the year ended December 31, 2015, Legacy recognized $633.8 million of impairment expense, $598.1 million of which was in 218 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2015, which decreased the expected future cash flows below the carrying value of the assets. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2014, Legacy recognized $448.7 million of impairment expense, $413.3 million of which was in 250 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2014, which decreased the expected future cash flows below the carrying value of the assets. As Legacy has historically grown through the acquisition of oil and natural gas properties, most of which were acquired during higher commodity price environments, the sharp decline in oil and natural gas prices during the latter portion of 2014 resulted in a corresponding decrease in the expected future cash flows of such assets from the date of their acquisition as compared to December 31, 2014. As evidenced above, this decrease was not limited to any one field or area of operation, as it impacted the value of assets across Legacy's portfolio. The remainder of the impairment related primarily to unproven properties. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Legacy did not recognize impairment expense on unproved properties during the year ended December 31, 2016. During the years ended December 31, 2015 and 2014, Legacy recognized $35.7 million and $35.0 million of impairment of unproven properties, respectively. (d) Oil, NGLs and Natural Gas Reserve Quantities Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with SEC rules and accounting standards. Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered. (e) Income Taxes Legacy is structured as a limited partnership, which is a pass-through entity for United States income tax purposes. The State of Texas has a margin-based franchise tax law that is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. Legacy recorded income tax (expense) benefit of $(1.2) million, $1.5 million and $0.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, which consists primarily of the Texas margin tax and federal income tax on a corporate subsidiary which employs full and part-time personnel providing services to the Partnership. The Partnership’s total effective tax rate differs from statutory rates for federal and state purposes primarily due to being structured as a limited partnership, which is a pass-through entity for federal income tax purposes. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $1.3 billion at December 31, 2016. (f) Derivative Instruments and Hedging Activities Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Notes 8 and 9). (g) Use of Estimates Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, impairment of oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. (h) Revenue Recognition Sales of crude oil, NGLs and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2016, 2015 and 2014. (i) Investments Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition. (j) Intangible assets Legacy has capitalized certain operating rights acquired in the acquisition of oil and natural gas properties. The operating rights, which have no residual value, are amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense is included as an element of depletion, depreciation, amortization and accretion expense. Impairment is assessed on a quarterly basis or when there is a material change in the remaining useful life. The expected amortization expenses for 2017, 2018, 2019, 2020 and 2021 are $396,000, $358,000, $349,000, $322,000 and $223,000, respectively. (k) Environmental Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. (l) Income (Loss) Per Unit Basic income (loss) per unit amounts are calculated after deducting distributions paid to Legacy's Preferred Units using the weighted average number of units outstanding during each period. Diluted income (loss) per unit also give effect to dilutive unvested restricted units (calculated based upon the treasury stock method) (see Note 12). (m) Segment Reporting Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes. (n) Unit-Based Compensation Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises and certain phantom unit awards, Legacy accounts for these awards under the liability method, which requires the Partnership to recognize the fair value of each unit option at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounts for executive phantom unit and restricted unit awards under the equity method. Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at December 31, 2016, do not include 484,447 units related to unvested restricted unit awards. (o) Accrued Oil and Natural Gas Liabilities Below are the components of accrued oil and natural gas liabilities as of December 31, 2016 and 2015.
(p) Restricted Cash Restricted cash of $3.6 million as of December 31, 2016 is recorded in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. There was no restricted cash recorded at December 31, 2015. (q) Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this annual report on Form 10-K. Please read "—Footnote 3—Long-Term Debt" for further discussion regarding this reclassification. (r) Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on our results of operations, cash flows or financial position. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements. We are currently determining the impacts of the new standard on our contract portfolio. Our approach includes performing a detailed review of key contracts representative of our business and comparing historical accounting policies and practices to the new standard. Our contracts are primarily short-term in nature, and our assessment at this stage is that we do not expect the new revenue recognition standard will have a material impact on our financial statements upon adoption. |
Fair Values of Financial Instruments |
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Fair Values of Financial Instruments | Fair Values of Financial Instruments The estimated fair values of Legacy’s financial instruments approximate the carrying amounts except as discussed below: Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The carrying amount of the second lien term loan debt under Legacy’s term loan credit agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar borrowings. The fair value of the 8% senior notes due 2020 (the "2020 Senior Notes") and the 6.625% senior notes due 2021 (the "2021 Senior Notes") was $179.4 million and $302.0 million, respectively, as of December 31, 2016. As these valuations are based on unadjusted quoted prices in an active market, the fair values would be classified as Level 1. Long-term incentive plan obligations. See Note 13 for discussion of process used in estimating the fair value of the long-term incentive plan obligations. Derivatives. See Note 8 for discussion of process used in estimating the fair value of commodity price and interest rate derivatives. Fair Value Measurements Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Fair Value on a Recurring Basis The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015:
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Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including costless collars, three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for our oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counterparties (or their affiliates) are also current or former bank lenders under the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change. The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("ARO") estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these measurements as Level 3. A reconciliation of the beginning and ending balances of Legacy’s ARO is presented in Note 11. Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2016 and 2015 consist of:
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commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. The remaining $35.7 million of impairment during the year ended December 31, 2015 was related to unproved properties acquired since 2010 that were no longer viable.
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Long-Term Debt |
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Long-Term Debt | Long-Term Debt Long-term debt consists of the following at December 31, 2016 and 2015:
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Credit Facility Previous Credit Agreement: On March 10, 2011, Legacy entered into a five-year $1 billion secured revolving credit facility (as amended, the "Previous Credit Agreement"). Borrowings under the Previous Credit Agreement were set to mature on March 10, 2016. Current Credit Agreement: On April 1, 2014, Legacy entered into a five-year $1.5 billion secured revolving credit facility with Wells Fargo Bank, National Association, as administrative agent, as amended through the Seventh Amendment, (the "Current Credit Agreement") which replaced the Previous Credit Agreement. Borrowings under the Current Credit Agreement mature on April 1, 2019. Legacy's obligations under the Current Credit Agreement are secured by mortgages on over 95% of the total value of its oil and natural gas properties as well as a pledge of all of its ownership interests in its operating subsidiaries. The amount available for borrowing at any one time is limited to the lesser of the borrowing base and the facility amount and contains a $2 million sub-limit for letters of credit. The borrowing base at December 31, 2016 was set at $600 million. The borrowing base is subject to semi-annual redeterminations on April 1 and October 1 of each year. Any borrowings in excess of the redetermined borrowing base must be repaid. Additionally, either Legacy or the lenders may, once during each calendar year, elect to redetermine the borrowing base between scheduled redeterminations. Legacy also has the right, once during each calendar year, to request the redetermination of the borrowing base upon the proposed acquisition of certain oil and natural gas properties where the purchase price is greater than 10% of the borrowing base then in effect. Any increase in the borrowing base requires the consent of all the lenders and any decrease in or maintenance of the borrowing base must be approved by the lenders holding at least 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement. If the requisite lenders do not agree on an increase or decrease, then the borrowing base will be the highest borrowing base acceptable to the lenders holding 66-2/3% of the outstanding aggregate principal amounts of the loans or participation interests in letters of credit issued under the Current Credit Agreement so long as it does not increase the borrowing base then in effect. Under the Current Credit Agreement, interest on debt outstanding is charged based on Legacy's selection of a one-, two-, three- or six-month LIBOR rate plus 1.5% to 2.5%, or the ABR which equals the highest of the prime rate, the Federal funds effective rate plus 0.50% or one-month LIBOR plus 1.00%, plus an applicable margin from 0.5% to 1.5% per annum, determined by the percentage of the borrowing base then in effect that is drawn. The Current Credit Agreement contains various covenants that limit Legacy's ability to: (i) incur indebtedness, (ii) enter into certain leases, (iii) grant certain liens, (iv) enter into certain swaps, (v) make certain loans, acquisitions, capital expenditures and investments, (vi) make distributions other than from available cash, (vii) merge, consolidate or allow any material change in the character of its business and (viii) engage in certain asset dispositions, including a sale of all or substantially all of its assets. Effective October 25, 2016, Legacy entered into an amendment (the “Eighth Amendment”) to the Current Credit Agreement with the Administrative Agent and certain other financial institutions party thereto as lenders to, among other items: (i) permit the issuance and use of the Second Lien Term Loans pursuant to the Second Lien Term Loan Credit Agreement (as defined below), (ii) increase the percentage of the total value of Legacy’s Oil and Gas Properties required to be subject to a mortgage to 95% of the value or the most recently evaluated Reserve Report and grant a mortgage on certain identified undeveloped acreage in the Permian Basin, (iii) require Legacy to grant a perfected security interest in its cash and securities accounts, subject to certain customary exceptions and (iv) allow Legacy to hedge on an unsecured basis with counterparties who (or whose credit support provider) has an issuer rating or whose long term senior unsecured debt rating of BBB-/Baa3. The Current Credit Agreement, as amended by the Eighth Amendment, also contains covenants that, among other things, require Legacy to maintain specified ratios or conditions. As of December 31, 2016 these covenants were as follows: (i) secured debt at any time to EBITDA for the four fiscal quarters ending on the last day of the fiscal quarter preceding such day of not more than 4.5 to 1.0 beginning with the fiscal quarter ending on December 31, 2018, (ii) as of the last day of the most recent quarter, total EBITDA over the last four quarters to total interest expense over the last four quarters to be greater than 2.0 to 1.0, (iii) consolidated current assets, as of the last day of the most recent quarter and including the unused amount of the total commitments, to consolidated current liabilities as of the last day of the most recent quarter of not less than 1.0 to 1.0, excluding non-cash assets and liabilities under FASB Accounting Standards Codification 815, which includes the current portion of oil, natural gas and interest rate derivatives and (iv) the ratio of (a) the sum of (i) the net present value using NYMEX forward pricing, discounted at 10 percent per annum, of Legacy’s proved developed producing oil and gas properties (“PDP PV-10”) as reflected in the most recent reserve report delivered either July 1 or December 31 of each year, as the case may be, beginning with the reserve report to be delivered on July 1, 2017 (giving pro forma effect to material acquisitions or dispositions since the date of such reports), (ii) the net mark to market value of Legacy’s swap agreements and (iii) Legacy’s cash and cash equivalents, in each case as of such date to (b) Secured Debt as of such day to be equal to or less than 1.00 to 1.00 beginning with the fiscal quarter ending June 30, 2017. All capitalized terms not defined in the foregoing description have the meaning assigned to them in the Current Credit Agreement Amendment, as amended by the Eighth Amendment. As of December 31, 2016, Legacy had outstanding borrowings of $463 million under the Current Credit Agreement at a weighted average interest rate of 3.91%. Thus, Legacy had approximately $135.1 million of borrowing availability remaining. As of February 21, 2017, Legacy had approximately $134.1 million of borrowing availability remaining. For the year ended December 31, 2016, Legacy paid $19.0 million of interest expense on the Current Credit Agreement. At December 31, 2016, Legacy was in compliance with all covenants contained in the Current Credit Agreement. Depending on future oil and natural gas prices, we could breach certain financial covenants under our revolving credit facility, which would constitute a default under our revolving credit facility. Such default, if not remedied, would require a waiver from our lenders in order for us to avoid an event of default and subsequent acceleration of all amounts outstanding under our revolving credit facility or foreclosure on our oil and natural gas properties. While no assurances can be made that, in the event of a covenant breach, such a waiver will be granted, we believe the long-term global outlook for commodity prices and our efforts to date, which include the suspension of distributions to our unitholders and Preferred Unitholders, as well as asset sales, will be viewed positively by our lenders. A default under Legacy's revolving credit facility could cause all of Legacy's existing indebtedness, including Legacy's Second Lien Term Loans (as defined below), 2020 Senior Notes and 2021 Senior Notes, to be immediately due and payable. Second Lien Term Loans On October 25, 2016, Legacy entered into a Term Loan Credit Agreement (the “Second Lien Term Loan Credit Agreement”) among Legacy, as borrower, Cortland Capital Market Services LLC, as administrative agent and second lien collateral agent, and the lenders party thereto, providing for term loans up to an aggregate principal amount of $300.0 million (the “Second Lien Term Loans”). GSO Capital Partners L.P. (“GSO”) and certain funds and accounts managed, advised or sub-advised, by GSO are the initial lenders thereunder. The Second Lien Term Loans are secured on a second lien priority basis by the same collateral that secures Legacy's Current Credit Agreement and are unconditionally guaranteed on a joint and several basis by the same wholly owned subsidiaries of Legacy that are guarantors under the Current Credit Agreement. Legacy used the initial $60.0 million of gross loan proceeds from its Second Lien Term Loan to repay outstanding indebtedness and pay associated transaction expenses. Additional Second Lien Term Loans up to an aggregate amount of $240.0 million are available at Legacy’s discretion for twelve months following the date of the Second Lien Term Loan Credit Agreement. The Second Lien Term Loans under the Second Lien Term Loan Credit Agreement will be issued with an upfront fee of 2% and bear interest at a rate of 12.00% per annum payable quarterly in cash or, prior to the 18 month anniversary of the Second Lien Term Loan Credit Agreement, Legacy may elect to pay in kind up to 50% of the interest payable. The Second Lien Term Loans may be used for general corporate purposes and for the repayment of outstanding indebtedness, in any case as may be approved by Legacy and GSO. For the first 24 months following the effective date of the Term Loan Credit Agreement, GSO may not assign more than 49% of the Second Lien Term Loans without the Partnership's consent. The Second Lien Term Loan Credit Agreement matures on August 31, 2021; provided that, if on July 1, 2020, Legacy has greater than or equal to a face amount of $15.0 million of Senior Notes that were outstanding on the date the Second Lien Term Loan Credit Agreement was entered into or any other senior notes with a maturity date that is earlier than August 31, 2021, the Second Lien Term Loan Credit Agreement will mature on August 1, 2020. The Second Lien Term Loan Credit Agreement contains customary prepayment provisions and make-whole premiums. Legacy will pay a quarterly fee of 0.250% on the average daily amount of the unused commitments under the Term Loan Credit Agreement. The Second Lien Term Loan Credit Agreement also contains covenants that, among other things, require us to maintain specified ratios or conditions as follows:
All capitalized terms used but not defined in the foregoing description have the meaning assigned to them in the Second Lien Term Loan Credit Agreement. For the year ended December 31, 2016, Legacy paid cash interest expense of $1.4 million under the Second Lien Term Loan Credit Agreement. 8% Senior Notes Due 2020 On December 4, 2012, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $300.0 million of our 8% Senior Notes due 2020 (the "2020 Senior Notes"), which were subsequently registered through a public exchange offer that closed on January 8, 2014. The 2020 Senior Notes were issued at 97.848% of par. Legacy has the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below.
Legacy may be required to offer to repurchase the 2020 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy and Legacy Reserves Finance Corporation's obligations under the 2020 Senior Notes are guaranteed by its 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of Legacy's wholly-owned subsidiaries other than Legacy Reserves Finance Corporation. In the future, the guarantees may be released or terminated under the following circumstances: (i) in connection with any sale or other disposition of all or substantially all of the properties of the guarantor; (ii) in connection with any sale or other disposition of sufficient capital stock of the guarantor so that it no longer qualifies as our Restricted Subsidiary (as defined in the indenture); (iii) if designated to be an unrestricted subsidiary; (iv) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture; (v) upon the liquidation or dissolution of the guarantor provided no default or event of default has occurred or is occurring; (vi) at such time the guarantor does not have outstanding guarantees of its, or any other guarantor's, other debt; or (vii) upon merging into, or transferring all of its properties to Legacy or another guarantor and ceasing to exist. Refer to Note 14 - Subsidiary Guarantors for further details on Legacy's guarantors. The indenture governing the 2020 Senior Notes limits Legacy's ability and the ability of certain of its subsidiaries to (i) sell assets; (ii) pay distributions on, repurchase or redeem equity interests or purchase or redeem Legacy's subordinated debt, provided that such subsidiaries may pay dividends to the holders of their equity interests (including Legacy) and Legacy may pay distributions to the holders of its equity interests subject to the absence of certain defaults, the satisfaction of a fixed charge coverage ratio test and so long as the amount of such distributions does not exceed the sum of available cash (as defined in the partnership agreement) at Legacy, net proceeds from the sales of certain securities and return of or reductions to capital from restricted investments; (iii) make certain investments; (iv) incur or guarantee additional indebtedness or issue preferred units; (v) create or incur certain liens; (vi) enter into agreements that restrict distributions or other payments from certain of its subsidiaries to Legacy; (vii) consolidate, merge or transfer all or substantially all of Legacy's assets; (viii) engage in certain transactions with affiliates; (ix) create unrestricted subsidiaries; and (x) engage in certain business activities. These covenants are subject to a number of important exceptions and qualifications. If at any time when the 2020 Senior Notes are rated investment grade by each of Moody's Investors Service, Inc. and Standard & Poor's Ratings Services and no Default (as defined in the indenture) has occurred and is continuing, many of such covenants will terminate and Legacy and its subsidiaries will cease to be subject to such covenants. Further, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2020 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness. The indenture also includes customary events of default. As of the December 31, 2016, The Partnership was in compliance with all covenants of the 2020 Senior Notes. Interest is payable on June 1 and December 1 of each year. During the year ended December 31, 2016, Legacy repurchased a face amount of $52.0 million of its 2020 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price. On June 1, 2016, Legacy exchanged 2,719,124 units representing limited partner interests in the Partnership for $15.0 million of face amount of its outstanding 2020 Senior Notes. Legacy treated this exchange as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2020 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the fair value of the units issued in the exchange based on the closing price on June 1, 2016. 6.625% Senior Notes Due 2021 On May 28, 2013, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of $250 million of our 6.625% Senior Notes due 2021 (the "2021 Senior Notes"), which were subsequently registered through a public exchange offer that closed on March 18, 2014. The 2021 Senior Notes were issued at 98.405% of par. On May 13, 2014, Legacy and its 100% owned subsidiary Legacy Reserves Finance Corporation completed a private placement offering to eligible purchasers of an aggregate principal amount of an additional $300 million of the 6.625% 2021 Senior Notes. These 2021 Senior Notes were issued at 99% of par. The terms of the 2021 Senior Notes, including details related to our guarantors, are substantially identical to the terms of the 2020 Senior Notes with the exception of the maturity date, interest rate and redemption provisions noted below. Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below.
Prior to June 1, 2017, Legacy may redeem all or any part of the 2021 Senior Notes at the “make-whole” redemption price as defined in the indenture. Legacy may be required to offer to repurchase the 2021 Senior Notes at a purchase price of 101% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in the event of a change of control as defined by the indenture. Legacy and Legacy Reserves Finance Corporation's obligations under the 2021 Senior Notes are guaranteed by the same parties and on the same terms as Legacy's 2020 Senior Notes discussed above. Further, if the lenders under Legacy's Current Credit Agreement were to accelerate the indebtedness under Legacy's Current Credit Agreement as a result of a default, such acceleration could cause a cross-default of all of the 2021 Senior Notes and permit the holders of such notes to accelerate the maturities of such indebtedness. As of December 31, 2016, the Partnership was in compliance with all covenants of the 2021 Senior Notes. Interest is payable on June 1 and December 1 of each year. During the year ended December 31, 2016, Legacy repurchased a face amount of $117.3 million of its 2021 Senior Notes on the open market. Legacy treated these repurchases as an extinguishment of debt. Accordingly, Legacy recognized a gain for the difference between (1) the face amount of the 2021 Senior Notes repurchased net of the unamortized portion of both the original issuer's discount and issuance costs and (2) the repurchase price. For the year ended December 31, 2016, Legacy paid $47.9 million of cash interest expense for the 2020 Senior Notes and 2021 Senior Notes. |
Acquisitions |
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Business Combinations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquisitions | Acquisitions WPX Acquisition On June 4, 2014, Legacy purchased a non-operated interest in oil and natural gas properties located in the Piceance Basin in Garfield County, Colorado from WPX Energy Rocky Mountain, LLC , a subsidiary of WPX Energy, Inc., (the "WPX Acquisition") for a net purchase price of $360.0 million. Consideration included both cash and 300,000 Incentive Distribution Units representing limited partner interests in the Partnership (the "Incentive Distribution Units"), 100,000 of which vested immediately and the remainder of which are available to vest and also subject to forfeiture pursuant to the terms of a related Incentive Distribution Units Holders Agreement. This acquisition was accounted for as a business combination. The 100,000 vested Incentive Distribution Units have been reflected in the financial statements at their estimated issuance date fair value of $30.8 million. No value was ascribed to the unvested Incentive Distribution Units upon the closing of the WPX Acquisition as the vesting of the unvested Incentive Distribution Units is dependent upon the consummation of future transactions with WPX and such Incentive Distribution Units will be a portion of the consideration of any such future transactions. During the year ended December 31, 2014, Legacy incurred acquisition costs, recorded in general and administrative expense, of approximately $5.4 million related to the WPX Acquisition and other acquisitions. The allocation of the WPX Acquisition purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands):
Anadarko Acquisitions On July 31, 2015, Legacy purchased (1) 100% of the issued and outstanding limited liability company membership interests in Dew Gathering LLC, which owns directly and indirectly natural gas gathering and processing assets in Anderson, Freestone, Houston, Leon, Limestone and Robertson Counties, Texas (the "WGR Acquisition") from WGR Operating LP ("WGR") for a net purchase price of $96.7 million, and (2) various oil and natural gas properties and associated production assets (the "Anadarko E&P Acquisition," together with the WGR Acquisition, the "Anadarko Acquisitions") from Anadarko E&P Onshore LLC ("Anadarko") for a net purchase price of $337.2 million. The purchase prices were financed with borrowings under Legacy’s revolving credit facility. The effective date of these purchases was April 1, 2015. The operating results from the Anadarko Acquisitions have been included from their acquisition on July 31, 2015. During the year ended December 31, 2015, Legacy incurred acquisition costs, recorded in general and administrative expense, of approximately $2.4 million related to the Anadarko Acquisitions and other acquisitions. The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands):
Pro Forma Operating Results The following table reflects the unaudited pro forma results of operations as though the WPX Acquisition had occurred on January 1, 2013 and the Anadarko Acquisitions had occurred on January 1, 2014. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:
The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the WPX Acquisition and the Anadarko Acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes.
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Related Party Transactions |
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Dec. 31, 2016 | |
Related Party Transactions [Abstract] | |
Related Party Transactions | Related Party Transactions Blue Quail Energy Services, LLC (“Blue Quail”), a company specializing in water transfer services, is an affiliate of Moriah Energy Services LLC, an entity which Cary D. Brown and Dale A. Brown, directors of Legacy, are principals. Legacy has contracted with Blue Quail to provide water transfer services and paid $98,297, $382,629 and $84,470 in 2016, 2015 and 2014, respectively to Blue Quail for such services. In mid-2015 Legacy performed a technical evaluation of a potential acquisition and, based on such evaluation and Legacy’s business model, subsequently decided not to pursue such acquisition. In September 2015, Moriah Powder River LLC, an oil and natural gas exploration and production company which Cary D. Brown and Dale Brown indirectly control, decided to pursue such opportunity and paid Legacy a one-time expense reimbursement of $500,000 to utilize Legacy's prior technical work product. Cary D. Brown and Kyle A. McGraw, Director and Legacy’s Executive Vice President and Chief Development Officer, own interests in partnerships which, in turn, own a combined non-controlling 4.16% interest as limited partners in a partnership which, until November 10, 2014, owned the building that Legacy occupies. Monthly rent is $111,299 without respect to property taxes and insurance. The lease expires in September 2020. |
Commitments and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Commitments and Contingencies From time to time Legacy is a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, Legacy is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows. Legacy is party to a contractual agreement, extending through 2022, to purchase CO2 volumes from a third party. The contract requires Legacy to purchase minimum annual volumes, the pricing of which is calculated as a percentage of NYMEX-WTI oil prices, with a floor of $57.14. Based upon the minimum required volumes and the NYMEX-WTI strip prices as of December 31, 2016, we estimate the value of our total future obligation to be approximately $48.6 million. Legacy is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of Legacy could be adversely affected. Legacy has employment agreements and retention bonus agreements with its officers and certain other employees. The employment agreements with its officers specify that if the officer is terminated by Legacy for other than cause or following a change in control, the officer shall receive severance pay ranging from 24 to 36 months salary plus bonus and COBRA benefits, respectively. The retention bonus agreements provide for fixed bonus amounts to be paid to employees contingent upon various criteria including their continuous employment or a change in control. |
Business and Credit Concentrations |
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Business and Credit Concentrations | Business and Credit Concentrations Cash Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash. Revenue and Accounts Receivable Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2016, 2015 or 2014. Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 10. Commodity Derivatives Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps, costless collars or three-way collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. Legacy values these transactions at fair value on a recurring basis (Note 8). As of December 31, 2016, Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $12.7 million, collectively. Legacy enters into commodity derivative transactions with members of its revolving credit facility, who Legacy’s management believes are major, creditworthy financial institutions. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis. Sales to Major Customers For the years ended December 31, 2016 and 2015, Legacy did not sell oil, NGL or natural gas production representing 10% or more of total revenue to any one customer. For the year ended December 31, 2014, Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below:
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Fair Value Measurements |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Fair Values of Financial Instruments The estimated fair values of Legacy’s financial instruments approximate the carrying amounts except as discussed below: Debt. The carrying amount of the revolving long-term debt approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar bank borrowings. The carrying amount of the second lien term loan debt under Legacy’s term loan credit agreement approximates fair value because Legacy’s current borrowing rate does not materially differ from market rates for similar borrowings. The fair value of the 8% senior notes due 2020 (the "2020 Senior Notes") and the 6.625% senior notes due 2021 (the "2021 Senior Notes") was $179.4 million and $302.0 million, respectively, as of December 31, 2016. As these valuations are based on unadjusted quoted prices in an active market, the fair values would be classified as Level 1. Long-term incentive plan obligations. See Note 13 for discussion of process used in estimating the fair value of the long-term incentive plan obligations. Derivatives. See Note 8 for discussion of process used in estimating the fair value of commodity price and interest rate derivatives. Fair Value Measurements Fair value is defined as the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
As required by ASC 820-10, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Legacy’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. Fair Value on a Recurring Basis The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015:
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Legacy estimates the fair values of the swaps based on published forward commodity price curves for the underlying commodities as of the date of the estimate for those commodities for which published forward pricing is readily available. For those commodity derivatives for which forward commodity price curves are not readily available, Legacy estimates, with the assistance of third-party pricing experts, the forward curves as of the date of the estimate. Legacy validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming, where applicable, that those securities trade in active markets. Legacy estimates the option value of puts and calls combined into hedges, including costless collars, three-way collars and enhanced swaps using an option pricing model which takes into account market volatility, market prices, contract parameters and discount rates based on published LIBOR rates and interest swap rates. Due to the lack of an active market for periods beyond one-month from the balance sheet date for our oil price differential swaps, Legacy has reviewed historical differential prices and known economic influences to estimate a reasonable forward curve of future pricing scenarios based upon these factors. In order to estimate the fair value of our interest rate swaps, Legacy uses a yield curve based on money market rates and interest rate swaps, extrapolates a forecast of future interest rates, estimates each future cash flow, derives discount factors to value the fixed and floating rate cash flows of each swap, and then discounts to present value all known (fixed) and forecasted (floating) swap cash flows. Curve building and discounting techniques used to establish the theoretical market value of interest bearing securities are based on readily available money market rates and interest swap market data. The determination of the fair values above incorporates various factors including the impact of our non-performance risk and the credit standing of the counterparties involved in the Partnership’s derivative contracts. The risk of nonperformance by the Partnership’s counterparties is mitigated by the fact that such current counterparties (or their affiliates) are also current or former bank lenders under the Partnership’s revolving credit facility. In addition, Legacy routinely monitors the creditworthiness of its counterparties. As the factors described above are based on significant assumptions made by management, these assumptions are the most sensitive to change. The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
During periods of market disruption, including periods of volatile oil and natural gas prices, rapid credit contraction or illiquidity, it may be difficult to value certain of the Partnerships’ derivative instruments if trading becomes less frequent and/or market data becomes less observable. There may be certain asset classes that were in active markets with observable data that become illiquid due to changes in the financial environment. In such cases, more derivative instruments may fall to Level 3 and thus require more subjectivity and management judgment. As such, valuations may include inputs and assumptions that are less observable or require greater estimation as well as valuation methods which are more sophisticated or require greater estimation thereby resulting in valuations with less certainty. Further, rapidly changing commodity and unprecedented credit and equity market conditions could materially impact the valuation of derivative instruments as reported within our consolidated financial statements and the period-to-period changes in value could vary significantly. Decreases in value may have a material adverse effect on our results of operations or financial condition. Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination, measurements of oil and natural gas property impairments, and the initial recognition of asset retirement obligations, for which fair value is used. These asset retirement obligation ("ARO") estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, Legacy has designated these measurements as Level 3. A reconciliation of the beginning and ending balances of Legacy’s ARO is presented in Note 11. Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2016 and 2015 consist of:
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commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. The remaining $35.7 million of impairment during the year ended December 31, 2015 was related to unproved properties acquired since 2010 that were no longer viable.
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Derivative Financial Instruments |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Derivative Financial Instruments | Derivative Financial Instruments Commodity derivative transactions Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps or collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from increases in the prices of oil and natural gas, it also reduces Legacy’s potential exposure to adverse price movements. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its production, provide only partial price protection against declines in oil and natural gas prices and limit Legacy’s potential gains from future increases in prices. None of these instruments are used for trading or speculative purposes. These derivative instruments are intended to mitigate a portion of Legacy’s price-risk and may be considered hedges for economic purposes, but Legacy has chosen not to designate them as cash flow hedges for accounting purposes. Therefore, all derivative instruments are recorded on the balance sheet at fair value with changes in fair value being recorded in current period earnings. By using derivative instruments to mitigate exposures to changes in commodity prices, Legacy exposes itself to credit risk and market risk. 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 Legacy, which creates credit risk. Legacy minimizes the credit or repayment risk in derivative instruments by entering into transactions with high-quality counterparties. The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended December 31, 2016, 2015, and 2014.
Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands):
As of December 31, 2016, Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
As of December 31, 2016, Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below:
As of December 31, 2016, Legacy had the following NYMEX WTI crude oil costless collars that combine a long put with a short call as indicated below:
As of December 31, 2016, Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below:
As of December 31, 2016, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and a fixed-price swap as indicated below:
As of December 31, 2016, Legacy had the following NYMEX Henry Hub and Waha natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
As of December 31, 2016, Legacy had the following NYMEX Henry Hub costless collars that combine a long put with a short call as indicated below:
As of December 31, 2016, Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below:
As of December 31, 2016, Legacy had the following Henry Hub NYMEX to Northwest Pipeline, SoCal and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below:
Interest rate derivative transactions Due to the volatility of interest rates, Legacy periodically enters into interest rate risk management transactions in the form of interest rate swaps for a portion of its outstanding debt balance. These transactions allow Legacy to reduce exposure to interest rate fluctuations. While the use of these arrangements limits Legacy’s ability to benefit from decreases in interest rates, it also reduces Legacy’s potential exposure to increases in interest rates. Legacy’s arrangements, to the extent it enters into any, apply to only a portion of its outstanding debt balance, provide only partial protection against interest rate increases and limit Legacy’s potential savings from future interest rate declines. It is never management’s intention to hold or issue derivative instruments for speculative trading purposes. Conditions sometimes arise where actual borrowings are less than notional amounts hedged which has and could result in overhedged amounts. Legacy does not designate these derivatives as cash flow hedges, even though they reduce its exposure to changes in interest rates. Therefore, the mark-to-market of these instruments is recorded in current earnings and classified as a component of interest expense. The total impact on interest expense from the mark-to-market and settlements was as follows:
The table below summarizes the interest rate swap assets and liabilities as of December 31, 2016.
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Sales to Major Customers |
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Risks and Uncertainties [Abstract] | |||||||||||||||||||||||||||||||
Sales to Major Customers | Business and Credit Concentrations Cash Legacy maintains its cash in bank deposit accounts, which, at times, may exceed federally insured amounts. Legacy has not experienced any losses in such accounts. Legacy believes it is not exposed to any significant credit risk on its cash. Revenue and Accounts Receivable Substantially all of Legacy’s accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the oil and natural gas industry. This concentration of customers and joint interest owners may impact Legacy’s overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, Legacy has not experienced significant credit losses on such receivables. No bad debt expense was recorded in 2016, 2015 or 2014. Legacy cannot ensure that such losses will not be realized in the future. A listing of oil and natural gas purchasers exceeding 10% of Legacy’s sales is presented in Note 10. Commodity Derivatives Due to the volatility of oil and natural gas prices, Legacy periodically enters into price-risk management transactions (e.g., swaps, enhanced swaps, costless collars or three-way collars) for a portion of its oil and natural gas production to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. Legacy values these transactions at fair value on a recurring basis (Note 8). As of December 31, 2016, Legacy’s commodity derivative transactions have a fair value favorable to the Partnership of $12.7 million, collectively. Legacy enters into commodity derivative transactions with members of its revolving credit facility, who Legacy’s management believes are major, creditworthy financial institutions. In addition, Legacy reviews and assesses the creditworthiness of these institutions on a routine basis. Sales to Major Customers For the years ended December 31, 2016 and 2015, Legacy did not sell oil, NGL or natural gas production representing 10% or more of total revenue to any one customer. For the year ended December 31, 2014, Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below:
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Asset Retirement Obligation |
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Asset Retirement Obligation | Asset Retirement Obligation An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset is recognized as a liability in the period in which it is incurred and becomes determinable. When liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the additions to the ARO asset and liability is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors; and (iv) a credit-adjusted risk-free interest rate. These inputs require significant judgments and estimates by the Partnership's management at the time of the valuation and are the most sensitive and subject to change. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon Legacy’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using Legacy’s credit-adjusted-risk-free rate. The carrying value of the ARO is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost. When obligations are relieved by sale of the property or plugging and abandoning the well, the related liability and asset costs are removed from Legacy's balance sheet. Any difference in the cost to plug and the related liability is recorded as a gain or loss on Legacy's income statement in the disposal of assets line item. The following table reflects the changes in the ARO during the years ended December 31, 2016, 2015 and 2014.
Each year the Partnership reviews and, to the extent necessary, revises its ARO estimates. During 2014, 2015 and 2016, no revisions of previous estimates were deemed necessary. |
Partners' Equity |
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Partners' Equity | Partners' Equity On April 17, 2014, Legacy issued 2,000,000 of its 8% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series A Preferred Units") in a public offering at a price of $25.00 per unit. On May 12, 2014 Legacy issued an additional 300,000 Series A Preferred Units pursuant to the underwriters’ option to purchase additional Series A Preferred Units. Legacy received aggregate net proceeds of approximately $55.2 million, after deducting underwriting discounts and offering expenses, from the offering of Series A Preferred Units during the year ended December 31, 2014. On June 17, 2014, Legacy issued 7,000,000 of its 8.00% Series B Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the "Series B Preferred Units") in a public offering at a price of $25.00 per unit. On July 1, 2014, Legacy issued an additional 200,000 Series B Preferred Units pursuant to the underwriters' option to purchase additional Series B Preferred Units. Legacy received aggregate net proceeds of approximately $174.3 million, after deducting underwriting discounts and offering expenses, from the offering of Series B Preferred Units during the year ended December 31, 2014. Distributions on the Series A Preferred Units and Series B Preferred Units (collectively, the "Preferred Units") are cumulative from the date of original issue and will be payable monthly in arrears on the 15th day of each month of each year, when, as and if declared by the board of directors of the Partnership's general partner. Distributions on the Series A Preferred Units will be payable from, and including, the date of the original issuance to, but not including April 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions on the Series B Preferred Units will be payable from, and including, the date of the original issuance to, but not including June 15, 2024 at an initial rate of 8.00% per annum of the stated liquidation preference. Distributions accruing on and after April 15, 2024 for the Series A Preferred Units and June 15, 2024 for the Series B Preferred Units will accrue at an annual rate equal to the sum of (a) three-month LIBOR as calculated on each applicable date of determination and (b) 5.24% for Series A Preferred Units and 5.26% for Series B Preferred Units, based on the $25.00 liquidation preference per preferred unit. At any time on or after April 15, 2019 or June 15, 2019, Legacy may redeem the Series A Preferred Units or Series B Preferred Units, respectively, in whole or in part at a redemption price of $25.00 per Preferred Unit plus an amount equal to all accumulated and unpaid distributions thereon through and including the date of redemption, whether or not declared. Legacy may also redeem the Preferred Units in the event of a change of control. The Series A Preferred Units and the Series B Preferred Units trade on the NASDAQ Global Select Market under the symbols "LGCYP" and "LGCYO,” respectively. On January 21, 2016, Legacy announced that its general partner suspended monthly cash distribution for both its Series A Preferred Units and its Series B Preferred Units. As of December 31, 2016, $1.92 of distributions per unit were in arrears, representing a total cumulative arrearage of approximately $18.2 million. Incentive Distribution Units On June 4, 2014, Legacy issued 300,000 Incentive Distribution Units to WPX Energy Rocky Mountain, LLC (“WPX”) as part of the WPX Acquisition. The Incentive Distribution Units issued to WPX include 100,000 Incentive Distribution Units that immediately vested along with the ability to vest in up to an additional 200,000 Incentive Distribution Units (the “Unvested IDUs”) in connection with any future asset sales or transactions completed with Legacy pursuant to the terms of the IDR Holders Agreement. Incentive Distribution Units that are not issued to WPX or other parties will remain in Legacy's treasury for the benefit of all limited partners until such time as Legacy may make future issuances of Incentive Distribution Units. The Incentive Distribution Units represent a right to incremental cash distributions from Legacy after certain target levels of distributions are paid to unitholders, which targets are set above the current levels of Legacy's distributions to unitholders. The Unvested IDUs do not participate in cash distributions from Legacy until vested. The Unvested IDUs will automatically be forfeited on each of the first two anniversaries of the closing date of the WPX Acquisition in an amount per forfeiture equal to 66,666 Incentive Distribution Units and on the third anniversary of the closing date of the WPX Acquisition in an amount equal to 66,668 Incentive Distribution Units. 66,666 unvested IDUs were forfeited on each of June 4, 2015 and June 4, 2016. Unvested IDUs that have not been forfeited will vest ratably at a rate of 10,000 Incentive Distribution Units per $35.5 million of additional cash consideration that is paid by Legacy to WPX or to a third party (along with the fair market value of any non-cash consideration) in connection with the consummation of any transaction by which Legacy acquires oil and natural gas properties (or rights therein or other assets related thereto) from WPX or jointly with WPX. In addition, the vested and outstanding Incentive Distribution Units held by WPX may be converted by Legacy, subject to applicable conversion factors, into units on a one-for-one basis at any time when Legacy has made a distribution in respect of its units for each of the four full fiscal quarters prior to the delivery of its conversion notice, and the amount of the distribution in respect of the units for the full quarter immediately preceding delivery of its conversion notice was equal to at least $0.90 per unit; and the amount of all distributions during each quarter within the four-quarter period immediately preceding delivery of its conversion notice did not exceed the adjusted operating surplus, as defined in Legacy's Partnership Agreement, for such quarter. Further, WPX also has the ability to similarly convert any of its vested Incentive Distribution Units beginning three years after June 4, 2014. WPX may not transfer any of the Incentive Distribution Units it holds to any person that is not a controlled affiliate of WPX. Loss per unit The following table sets forth the computation of basic and diluted loss per unit:
As of December 31, 2016, 484,447 restricted units and 1,212,692 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. Additionally, as the conditions for conversion on the Incentive Distribution Units have not been met, they have been excluded from the calculation. As of December 31, 2015, 550,447 restricted units and 862,064 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. As of December 31, 2014, 254,183 restricted units and 323,965 phantom units were excluded from the calculation of diluted earnings per unit due to their anti-dilutive effect. |
Unit-Based Compensation |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unit-Based Compensation | Unit-Based Compensation Long Term Incentive Plan On March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created and Legacy adopted the LTIP for its employees, consultants and directors, its affiliates and its general partner. The awards under the long-term incentive plan may include unit grants, restricted units, phantom units, unit options and unit appreciation rights (“UARs”). The LTIP permits the grant of awards that may be made or settled in units up to an aggregate of 5,000,000 units. As of December 31, 2016 grants of awards net of forfeitures and, in the case of phantom units, historical exercises covering 2,926,889 units have been made, comprised of 266,014 unit option awards, 1,014,499 restricted unit awards, 1,212,692 phantom unit awards and 433,684 unit awards. The UAR awards granted under the LTIP may only be settled in cash, and therefore are not included in the aggregate number of units granted under the LTIP. The LTIP is administered by the compensation committee of the board of directors ("Compensation Committee") of Legacy’s general partner. The cost of employee services in exchange for an award of equity instruments is measured based on a grant-date fair value of the award (with limited exceptions), and that cost must generally be recognized over the vesting period of the award. However, if an entity that nominally has the choice of settling awards by issuing units predominately settles in cash, or if an entity usually settles in cash whenever an employee asks for cash settlement, the entity is settling a substantive liability rather than repurchasing an equity instrument. Due to Legacy’s historical practice of settling options, UARs and certain phantom unit awards in cash, Legacy accounts for unit options, UARS and certain phantom unit awards by utilizing the liability method. The liability method requires companies to measure the cost of the employee services in exchange for a cash award based on the fair value of the underlying security at the end of each reporting period until settlement. Compensation cost is recognized based on the change in the liability between periods. Unit Appreciation Rights A UAR is a notional unit that entitles the holder, upon vesting, to receive cash valued at the difference between the closing price of units on the exercise date and the exercise price, as determined on the date of grant. Because these awards are settled in cash, Legacy accounts for the UARs under the liability method. During the year ended December 31, 2014, Legacy issued (i) 136,100 UARs to employees which vest ratably over a three-year period and (ii) 105,174 UARs to employees which cliff-vest at the end of a three-year period. During the year ended December 31, 2015, Legacy issued (i) 204,500 UARs to employees which vest ratably over a three-year period and (ii) 96,520 UARs to employees which cliff-vest at the end of a three-year period. Legacy did not issue UARs to employees during the year ended December 31, 2016. All of the UARs granted in 2015 and 2014 expire seven years from the grant date and are exercisable when they vest. For the years ended December 31, 2016, 2015 and 2014, Legacy recorded compensation expense (benefit) of $223.6 thousand, $(10.7) thousand and $(1,260.0) thousand, respectively, due to the changes in the compensation liability related to the above awards based on its use of the Black-Scholes model to estimate the December 31, 2016, 2015 and 2014 fair value of these UARs (see Note 8). As of December 31, 2016, there was a total of $129,093 of unrecognized compensation costs related to the unexercised and non-vested portion of the UARs. At December 31, 2016, this cost was expected to be recognized over a weighted-average period of 1.59 years. Compensation expense is based upon the fair value as of the balance sheet date and is recognized as a percentage of the service period satisfied. Based on historical data, Legacy has assumed a volatility factor of approximately 87% and employed the Black-Scholes model to estimate the December 31, 2016 fair value to be realized as compensation cost based on the percentage of the service period satisfied. Based on historical data, Legacy has assumed an estimated forfeiture rate of 5.3%. The Partnership will adjust the estimated forfeiture rate based upon actual experience. Legacy has assumed an annual distribution rate of $0.00 per unit. A summary of UAR activity for the year ended December 31, 2016, 2015 and 2014 is as follows:
The following table summarizes the status of the Partnership’s non-vested UARs since January 1, 2016:
Legacy has used a weighted-average risk free interest rate of 1.6% in its Black-Scholes calculation of fair value, which approximates the U.S. Treasury interest rates at December 31, 2016. Expected life represents the period of time that options and UARs are expected to be outstanding and is based on the Partnership’s best estimate. The following table represents the weighted average assumptions used for the Black-Scholes option-pricing model:
Phantom Units Legacy has also issued phantom units under the LTIP to executive officers. A phantom unit is a notional unit that entitles the holder, upon vesting, to receive either one Partnership unit for each phantom unit or the cash equivalent of a Partnership unit, as stipulated by the form of the grant. Legacy accounts for the phantom units settled in Partnership units under the equity method. Legacy accounts for the phantom units settled in cash under the liability method. During March 2014, the Compensation Committee approved the award of 117,197 subjective, or service-based, phantom units and 102,572 objective, or performance-based, phantom units to Legacy’s five executive officers. During March 2015, the Compensation Committee approved the award of 341,251 subjective, or service-based, phantom units and 259,998 objective, or performance-based, phantom units to Legacy’s executive officers. During June 2016, the Compensation Committee approved with respect to Paul Horne, and the board of directors of LRGPLLC approved the recommendation of the Compensation Committee with respect to the other executive officers the award of a maximum of 391,674 subjective, or service-based, phantom units that, upon vesting, settle in Partnership units, a maximum of 1,286,930 subjective phantom units that, upon vesting, settle in cash and a maximum of 2,238,138 objective, or performance-based, phantom units that, upon vesting, settle in cash to Legacy's executive officers. Compensation expense related to the phantom units and associated DERs was $3.7 million, $3.4 million and $2.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. Restricted Units During the year ended December 31, 2014, Legacy issued an aggregate of 127,845 restricted units to non-executive employees . The majority of these restricted units awarded vest ratably over a three-year period. During the year ended December 31, 2015, Legacy issued an aggregate of 381,860 restricted units to both non-executive employees and an executive employee. The restricted units awarded to non-executive employees vest ratably over a three-year period beginning at the date of grant. The restricted units granted to the executive employee vest ratably over a three-year period for a portion of the restricted units, with the remainder vesting in full at the end of a five-year period. During the year ended December 31, 2016, Legacy issued an aggregate of 137,569 restricted units to non-executive employees. The restricted units vest ratably over a three-year period beginning at the date of grant. Compensation expense related to restricted units was $2.7 million, $2.7 million and $2.3 million for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016, there was a total of $2.4 million of unrecognized compensation costs related to the non-vested portion of these restricted units. At December 31, 2016, this cost was expected to be recognized over a weighted-average period of 1.8 years. Pursuant to the provisions of ASC 718, Legacy’s issued units as reflected in the accompanying consolidated balance sheet at December 31, 2016, do not include 484,447 units related to unvested restricted unit awards. Board Units On May 15, 2014, Legacy granted and issued 3,628 units to each of its six non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $27.50 at the time of issuance. On June 15, 2015, Legacy granted and issued 11,025 units to each of its five non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $9.13 at the time of issuance. On May 10, 2016, Legacy granted and issued 39,526 units to each of its six non-employee directors as part of their annual compensation for serving on the board of directors of Legacy’s general partner. The value of each unit was $2.59 at the time of issuance. None of these units were subject to vesting. Legacy recognized the expense associated with the unit grants on the date of grant. |
Subsidiary Guarantors |
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Guarantees [Abstract] | |
Subsidiary Guarantors | Subsidiary Guarantors On October 17, 2014, we filed a registration statement on Form S-3 with the Securities and Exchange Commission ("SEC") to register the issuance and sale of, among other securities, our debt securities, which may be co-issued by Legacy Reserves Finance Corporation. The registration statement also registered guarantees of debt securities by Legacy Reserves Operating GP, LLC, Legacy Reserves Operating LP and Legacy Reserves Services, Inc. The Partnership's 2020 Senior Notes were issued in a private offering on December 4, 2012 and were subsequently registered through a public exchange offer that closed on January 8, 2014. The Partnership's 2021 Senior Notes were issued in two separate private offerings on May 28, 2013 and May 8, 2014. $250 million aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on March 18, 2014. The remaining $300 million of aggregate principal amount of our 2021 Senior Notes were subsequently registered through a public exchange offer that closed on February 10, 2015. The 2020 Senior Notes and the 2021 Senior Notes are guaranteed by our 100% owned subsidiaries Legacy Reserves Operating GP LLC, Legacy Reserves Operating LP, Legacy Reserves Services, Inc., Legacy Reserves Energy Services LLC, Dew Gathering LLC and Pinnacle Gas Treating LLC, which constitute all of our wholly-owned subsidiaries other than Legacy Reserves Finance Corporation, and certain other future subsidiaries (the “Guarantors”, together with any future 100% owned subsidiaries that guarantee the Partnership's 2020 Senior Notes and 2021 Senior Notes, the “Subsidiaries”). The Subsidiaries are 100% owned by the Partnership and the guarantees by the Subsidiaries are full and unconditional, except for customary release provisions described in Note 3 - Long-Term Debt. The Partnership has no assets or operations independent of the Subsidiaries, and there are no significant restrictions upon the ability of the Subsidiaries to distribute funds to the Partnership. The guarantees constitute joint and several obligations of the Guarantors. |
Summary of Significant Accounting Policies (Policies) |
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Dec. 31, 2016 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation | The accompanying financial statements have been prepared on the accrual basis of accounting whereby revenues are recognized when earned, and expenses are recognized when incurred. |
Accounts Receivable | Accounts Receivable Accounts receivable are recorded at the invoiced amount and do not bear interest. Legacy routinely assesses the financial strength of its customers. Bad debts are recorded based on an account-by-account review. Accounts are written off after all means of collection have been exhausted and potential recovery is considered remote. Legacy does not have any off-balance-sheet credit exposure related to its customers (see Note 10). |
Oil and Natural Gas Properties and Oil, NGLs and Natural Gas Reserve Quantities | Oil and Natural Gas Properties Legacy accounts for oil and natural gas properties using the successful efforts method. Under this method of accounting, costs relating to the acquisition and development of proved areas are capitalized when incurred. The costs of development wells are capitalized whether productive or non-productive. Leasehold acquisition costs are capitalized when incurred. If proved reserves are found on an unproved property, leasehold cost is transferred to proved properties. Exploration dry holes are charged to expense when it is determined that no commercial reserves exist. Other exploration costs, including personnel costs, geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense when incurred. The costs of acquiring or constructing support equipment and facilities used in oil and gas producing activities are capitalized. Production costs are charged to expense as incurred and are those costs incurred to operate and maintain our wells and related equipment and facilities. Depreciation and depletion of producing oil and natural gas properties is recorded based on units of production. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described below, proved reserves are estimated annually by Legacy’s independent petroleum engineer, LaRoche Petroleum Consultants, Ltd. ("LaRoche"), and are subject to future revisions based on availability of additional information. Legacy’s in-house reservoir engineers prepare an updated estimate of reserves each quarter. Depletion is calculated each quarter based upon the latest estimated reserves data available. As discussed in Note 11, asset retirement costs are recognized when the asset is placed in service, and are amortized over proved developed reserves using the units of production method. Asset retirement costs are estimated by Legacy’s engineers using existing regulatory requirements and anticipated future inflation rates. Upon sale or retirement of complete fields of depreciable or depletable property, the book value thereof, less proceeds from sale or salvage value, is charged to income. On sale or retirement of an individual well the proceeds are credited to accumulated depletion and depreciation. Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. Legacy compares net capitalized costs of proved oil and natural gas properties to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. These future price scenarios reflect Legacy’s estimation of future price volatility. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. Significant inputs used to determine the fair values of proved properties 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 underlying commodity prices embedded in Legacy's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. For the year ended December 31, 2016, Legacy recognized $61.8 million of impairment expense in 43 separate producing fields, due primarily to well performance and the further decline in commodity prices during the year ended December 31, 2016, which decreased the expected future cash flows below the carrying value of the assets. For the year ended December 31, 2015, Legacy recognized $633.8 million of impairment expense, $598.1 million of which was in 218 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2015, which decreased the expected future cash flows below the carrying value of the assets. The remainder of the impairment related primarily to unproven properties. For the year ended December 31, 2014, Legacy recognized $448.7 million of impairment expense, $413.3 million of which was in 250 separate producing fields, due to the significant decline in commodity prices during the year ended December 31, 2014, which decreased the expected future cash flows below the carrying value of the assets. As Legacy has historically grown through the acquisition of oil and natural gas properties, most of which were acquired during higher commodity price environments, the sharp decline in oil and natural gas prices during the latter portion of 2014 resulted in a corresponding decrease in the expected future cash flows of such assets from the date of their acquisition as compared to December 31, 2014. As evidenced above, this decrease was not limited to any one field or area of operation, as it impacted the value of assets across Legacy's portfolio. The remainder of the impairment related primarily to unproven properties. Unproven properties that are individually significant are assessed for impairment and if considered impaired are charged to expense when such impairment is deemed to have occurred. Legacy did not recognize impairment expense on unproved properties during the year ended December 31, 2016. During the years ended December 31, 2015 and 2014, Legacy recognized $35.7 million and $35.0 million of impairment of unproven properties, respectively. (d) Oil, NGLs and Natural Gas Reserve Quantities Legacy’s estimates of proved reserves are based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. LaRoche prepares a reserve and economic evaluation of all Legacy’s properties on a case-by-case basis utilizing information provided to it by Legacy and information available from state agencies that collect information reported to it by the operators of Legacy’s properties. The estimates of Legacy’s proved reserves have been prepared and presented in accordance with SEC rules and accounting standards. Reserves and their relation to estimated future net cash flows impact Legacy’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Legacy prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firm described above adheres to the same guidelines when preparing the reserve report. The accuracy of Legacy’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates. Legacy’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil, NGLs and natural gas eventually recovered. |
Income Taxes | Income Taxes Legacy is structured as a limited partnership, which is a pass-through entity for United States income tax purposes. The State of Texas has a margin-based franchise tax law that is commonly referred to as the Texas margin tax and is assessed at a 1% rate. Corporations, limited partnerships, limited liability companies, limited liability partnerships and joint ventures are examples of the types of entities that are subject to the tax. The tax is considered an income tax and is determined by applying a tax rate to a base that considers both revenues and expenses. Legacy recorded income tax (expense) benefit of $(1.2) million, $1.5 million and $0.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, which consists primarily of the Texas margin tax and federal income tax on a corporate subsidiary which employs full and part-time personnel providing services to the Partnership. The Partnership’s total effective tax rate differs from statutory rates for federal and state purposes primarily due to being structured as a limited partnership, which is a pass-through entity for federal income tax purposes. Net income for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. In addition, individual unitholders have different investment bases depending upon the timing and price of acquisition of their common units, and each unitholder’s tax accounting, which is partially dependent upon the unitholder’s tax position, differs from the accounting followed in the consolidated financial statements. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $1.3 billion at December 31, 2016. |
Derivative Instruments and Hedging Activities | Derivative Instruments and Hedging Activities Legacy uses derivative financial instruments to achieve more predictable cash flows by reducing its exposure to oil and natural gas price fluctuations and interest rate changes. Legacy does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices and interest rates. Therefore, Legacy records the change in the fair market values of oil and natural gas derivatives in current earnings. Changes in the fair values of interest rate derivatives are recorded in interest expense (see Notes 8 and 9). |
Use of Estimates | Use of Estimates Management of Legacy has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ materially from those estimates. Estimates which are particularly significant to the consolidated financial statements include estimates of oil and natural gas reserves, valuation of derivatives, impairment of oil and natural gas properties, depreciation, depletion and amortization, asset retirement obligations and accrued revenues. |
Revenue Recognition | Revenue Recognition Sales of crude oil, NGLs and natural gas are recognized when the delivery to the purchaser has occurred and title has been transferred. This occurs when oil or natural gas has been delivered to a pipeline or a tank lifting has occurred. Crude oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. Virtually all of Legacy’s natural gas contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of natural gas, and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. As a result, Legacy’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. Legacy believes that the pricing provisions of its oil and natural gas contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded as “Accounts receivable - oil and natural gas” in the accompanying consolidated balance sheets. Natural gas imbalances occur when Legacy sells more or less than its entitled ownership percentage of total natural gas production. Any amount received in excess of its share is treated as a liability. If Legacy receives less than its entitled share, the underproduction is recorded as a receivable. Legacy did not have any significant natural gas imbalance positions as of December 31, 2016, 2015 and 2014. |
Investments | Investments Undivided interests in oil and natural gas properties owned through joint ventures are consolidated on a proportionate basis. Investments in entities where Legacy exercises significant influence, but not a controlling interest, are accounted for by the equity method. Under the equity method, Legacy’s investments are stated at cost plus the equity in undistributed earnings and losses after acquisition. |
Intangible assets | Intangible assets Legacy has capitalized certain operating rights acquired in the acquisition of oil and natural gas properties. The operating rights, which have no residual value, are amortized over their estimated economic life of approximately 15 years beginning July 1, 2006. Amortization expense is included as an element of depletion, depreciation, amortization and accretion expense. Impairment is assessed on a quarterly basis or when there is a material change in the remaining useful life. |
Environmental | Environmental Legacy is subject to extensive federal, state and local environmental laws and regulations. These laws, which are frequently changing, regulate the discharge of materials into the environment and may require Legacy to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation are probable, and the costs can be reasonably estimated. Such liabilities are generally undiscounted unless the timing of cash payments is fixed and readily determinable. |
Income (Loss) Per Unit | Income (Loss) Per Unit Basic income (loss) per unit amounts are calculated after deducting distributions paid to Legacy's Preferred Units using the weighted average number of units outstanding during each period. Diluted income (loss) per unit also give effect to dilutive unvested restricted units (calculated based upon the treasury stock method) (see Note 12). |
Segment Reporting | Segment Reporting Legacy’s management initially treats each new acquisition of oil and natural gas properties as a separate operating segment. Legacy aggregates these operating segments into a single segment for reporting purposes. |
Unit-Based Compensation | Unit-Based Compensation Concurrent with its formation on March 15, 2006, a Long-Term Incentive Plan (“LTIP”) for Legacy was created. Due to Legacy’s history of cash settlements for option exercises and certain phantom unit awards, Legacy accounts for these awards under the liability method, which requires the Partnership to recognize the fair value of each unit option at the end of each period. Expense or benefit is recognized as the fair value of the liability changes from period to period. Legacy accounts for executive phantom unit and restricted unit awards under the equity method. Legacy’s issued units, as reflected in the accompanying consolidated balance sheet at December 31, 2016, do not include 484,447 units related to unvested restricted unit awards. |
Restricted Cash | Restricted Cash Restricted cash of $3.6 million as of December 31, 2016 is recorded in the "Prepaid expenses and other current assets" line. The restricted cash amounts represent various deposits to secure the performance of contracts, surety bonds and other obligations incurred in the ordinary course of business. There was no restricted cash recorded at December 31, 2015. |
Prior Year Financial Statement Presentation | Prior Year Financial Statement Presentation Certain prior year balances have been reclassified to conform to the current year presentation of balances as stated in this annual report on Form 10-K. Please read "—Footnote 3—Long-Term Debt" for further discussion regarding this reclassification. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements In August 2016, the Financial Accounting Standards Board ("FASB") issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force) to address diversity in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The adoption of this ASU will not have any material impact on our results of operations, cash flows or financial position. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients (“ASU No. 2016-12”). The amendments under this ASU do not change the core revenue recognition principle in Topic 606. In addition, ASU No. 2016-12 provide clarifying guidance in certain narrow areas and add some practical expedients. These amendments are also effective at the same date that Topic 606 is effective. In May 2016, the FASB issued ASU No. 2016-11, Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Updates 2014-09 and 2014-16 Pursuant to Staff Announcements at the March 3, 2016 EITF Meeting. Under this ASU, the SEC Staff is rescinding certain SEC Staff Observer comments that are codified in Topic 605, Revenue Recognition, and Topic 932, Extractive Activities-Oil and Gas, effective upon adoption of Topic 606. Revenue from Contracts with Customers (Topic 606) is effective for public entities for fiscal years, and interim periods within the fiscal years, beginning after December 15, 2017. In February 2016, the FASB issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"). ASU 2016-02 establishes a right-of-use (ROU) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. A modified retrospective transition approach is required for lessees for capital and operating leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements, with certain practical expedients available. We are currently evaluating the impact of our pending adoption of ASU 2016-02 on our consolidated financial statements. In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers" ("ASU 2014-09"), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The core principle of ASU 2014-09 is to recognize revenues when promised goods or services are transferred to customers in an amount that reflects the consideration to which an entity expects to be entitled for those goods or services. ASU 2014-09 defines a five step process to achieve this core principle and, in doing so, more judgment and estimates may be required within the revenue recognition process than are required under existing U.S. GAAP. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers" ("ASU 2015-14"), which approved a one-year delay of the standard's effective date. In accordance with ASU 2015-14, the standard is now effective for annual periods beginning after December 15, 2017, and interim periods therein, using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a retrospective approach with the cumulative effect of initially adopting ASU 2014-09 recognized at the date of adoption (which includes additional footnote disclosures). We are currently evaluating the impact of our pending adoption of ASU 2014-09 on our consolidated financial statements and do not anticipate the standard will have a material impact on our consolidated financial statements. We are currently determining the impacts of the new standard on our contract portfolio. Our approach includes performing a detailed review of key contracts representative of our business and comparing historical accounting policies and practices to the new standard. Our contracts are primarily short-term in nature, and our assessment at this stage is that we do not expect the new revenue recognition standard will have a material impact on our financial statements upon adoption. |
Summary of Significant Accounting Policies (Tables) |
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of components of accrued oil and natural gas liabilities | Below are the components of accrued oil and natural gas liabilities as of December 31, 2016 and 2015.
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Long-Term Debt (Tables) |
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Dec. 31, 2016 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of long-term debt | Long-term debt consists of the following at December 31, 2016 and 2015:
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8% Senior Notes due 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of debt redemption | Legacy has the option to redeem the 2020 Senior Notes, in whole or in part, at any time on or after December 1, 2016, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on December 1 of the years indicated below.
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6.625% Senior Notes due 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Instrument [Line Items] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of debt redemption | Legacy will have the option to redeem the 2021 Senior Notes, in whole or in part, at any time on or after June 1, 2017, at the specified redemption prices set forth below together with any accrued and unpaid interest, if any, to the date of redemption if redeemed during the twelve-month period beginning on June 1 of the years indicated below.
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Acquisitions (Tables) |
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of unaudited pro forma results of operations | The following table reflects the unaudited pro forma results of operations as though the WPX Acquisition had occurred on January 1, 2013 and the Anadarko Acquisitions had occurred on January 1, 2014. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:
The amounts of revenues and revenues in excess of direct operating expenses included in our consolidated statements of operations for the WPX Acquisition and the Anadarko Acquisitions are shown in the table that follows. Direct operating expenses include lease operating expenses and production and other taxes.
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WPX acquisition | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed | The allocation of the WPX Acquisition purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands):
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Anadarko Acquisitions | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Business Acquisition [Line Items] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of allocation of the purchase price to the fair value of the acquired assets and liabilities assumed | The allocation of the purchase price to the fair value of the acquired assets and liabilities assumed was as follows (in thousands):
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Fair Value Measurements (Tables) |
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of financial assets and liabilities that were accounted for at fair value on a recurring basis | The following table sets forth by level within the fair value hierarchy Legacy’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2016 and 2015:
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Reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 | The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy:
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Schedule of fair value measurements of proved oil and natural gas properties | Nonrecurring fair value measurements of proved oil and natural gas properties during the years ended December 31, 2016 and 2015 consist of:
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commodity prices embedded in the Company's estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that Legacy's management believes will impact realizable prices. The inputs used by management for the fair value measurements utilized in this review include significant unobservable inputs, and therefore, the fair value measurements employed are classified as Level 3 for these types of assets. The remaining $35.7 million of impairment during the year ended December 31, 2015 was related to unproved properties acquired since 2010 that were no longer viable.
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Derivative Financial Instruments (Tables) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of reconciliation of the changes in fair value of Legacy's commodity derivatives | The following table sets forth a reconciliation of the changes in fair value of Legacy's commodity derivatives for the years ended December 31, 2016, 2015, and 2014.
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Schedule of gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities | Certain of our commodity derivatives and interest rate derivatives are presented on a net basis on the Consolidated Balance Sheets. The following table summarizes the gross fair values of our derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on our Consolidated Balance Sheets as of the dates indicated below (in thousands):
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Schedule of notional amounts of outstanding derivative positions | As of December 31, 2016, Legacy had the following NYMEX WTI crude oil swaps paying floating prices and receiving fixed prices for a portion of its future oil production as indicated below:
As of December 31, 2016, Legacy had the following Midland-to-Cushing crude oil differential swaps paying a floating differential and receiving a fixed differential for a portion of its future oil production as indicated below:
As of December 31, 2016, Legacy had the following NYMEX WTI crude oil costless collars that combine a long put with a short call as indicated below:
As of December 31, 2016, Legacy had the following NYMEX WTI crude oil derivative three-way collar contracts that combine a long and short put with a short call as indicated below:
As of December 31, 2016, Legacy had the following NYMEX WTI crude oil enhanced swap contracts that combine a short put, a long put and a fixed-price swap as indicated below:
As of December 31, 2016, Legacy had the following NYMEX Henry Hub and Waha natural gas swaps paying floating natural gas prices and receiving fixed prices for a portion of its future natural gas production as indicated below:
As of December 31, 2016, Legacy had the following NYMEX Henry Hub costless collars that combine a long put with a short call as indicated below:
As of December 31, 2016, Legacy had the following NYMEX Henry Hub natural gas derivative three-way collar contracts that combine a long put, a short put and a short call as indicated below:
As of December 31, 2016, Legacy had the following Henry Hub NYMEX to Northwest Pipeline, SoCal and San Juan Basin natural gas differential swaps paying a floating differential and receiving a fixed differential for a portion of its future natural gas production as indicated below:
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Schedule of total impact on interest expense from the mark-to-market and settlements | The total impact on interest expense from the mark-to-market and settlements was as follows:
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Schedule of interest rate swap liabilities | The table below summarizes the interest rate swap assets and liabilities as of December 31, 2016.
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Sales to Major Customers (Tables) |
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Dec. 31, 2016 | |||||||||||||||||||||||||||||||
Risks and Uncertainties [Abstract] | |||||||||||||||||||||||||||||||
Schedule of revenue by major customer | For the year ended December 31, 2014, Legacy sold oil, NGL and natural gas production representing 10% or more of total revenues to purchasers as detailed in the table below:
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Asset Retirement Obligation (Tables) |
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Asset Retirement Obligation [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of changes in asset retirement obligations | The following table reflects the changes in the ARO during the years ended December 31, 2016, 2015 and 2014.
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Partners' Equity (Tables) |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of computation of basic and diluted income (loss) per unit | The following table sets forth the computation of basic and diluted loss per unit:
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Unit-Based Compensation (Tables) |
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Disclosure of Compensation Related Costs, Share-based Payments [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of option and UAR activity | A summary of UAR activity for the year ended December 31, 2016, 2015 and 2014 is as follows:
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Schedule of status of the Partnership’s non-vested UARs | The following table summarizes the status of the Partnership’s non-vested UARs since January 1, 2016:
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Schedule of weighted average assumptions used for the Black-Scholes option-pricing model | The following table represents the weighted average assumptions used for the Black-Scholes option-pricing model:
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Summary of Significant Accounting Policies - Income Taxes (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
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Income Tax Contingency [Line Items] | |||
Income tax (expense) benefit | $ (1,229) | $ 1,498 | $ 859 |
Partnership’s book basis in its net assets excess of Partnership’s net tax basis | $ 1,300,000 | ||
Texas | State jurisdiction | |||
Income Tax Contingency [Line Items] | |||
Franchise tax rate | 1.00% |
Summary of Significant Accounting Policies - Intangible Assets (Details) $ in Thousands |
12 Months Ended |
---|---|
Dec. 31, 2016
USD ($)
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Estimated economic useful life | 15 years |
Expected amortization expense, 2017 | $ 396 |
Expected amortization expense, 2018 | 358 |
Expected amortization expense, 2019 | 349 |
Expected amortization expense, 2020 | 322 |
Expected amortization expense, 2021 | $ 223 |
Summary of Significant Accounting Policies - Unit-Based Compensation (Details) - shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
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Restricted stock units (RSUs) | |||
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items] | |||
Antidilutive restricted units excluded from computation of EPS (in shares) | 484,447 | 550,447 | 254,183 |
Summary of Significant Accounting Policies - Accrued Oil and Natural Gas Liabilities (Details) - USD ($) $ in Thousands |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Revenue payable to joint interest owners | $ 19,576 | $ 15,253 |
Accrued lease operating expense | 17,696 | 19,007 |
Accrued capital expenditures | 7,019 | 2,881 |
Accrued ad valorem tax | 5,300 | 8,723 |
Other | 3,657 | 4,709 |
Accrued oil and natural gas liabilities | $ 53,248 | $ 50,573 |
Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($) |
Dec. 31, 2016 |
Dec. 31, 2015 |
---|---|---|
Organization, Consolidation and Presentation of Financial Statements [Abstract] | ||
Restricted cash | $ 3,600,000 | $ 0 |
Fair Values of Financial Instruments (Details) - Senior notes - USD ($) $ in Millions |
Dec. 31, 2016 |
May 13, 2014 |
May 28, 2013 |
Dec. 04, 2012 |
---|---|---|---|---|
8% Senior Notes due 2020 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Stated interest rate | 8.00% | 8.00% | ||
8% Senior Notes due 2020 | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair value of notes payable | $ 179.4 | |||
6.625% Senior Notes due 2021 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Stated interest rate | 6.625% | 6.625% | 6.625% | |
6.625% Senior Notes due 2021 | Level 1 | ||||
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items] | ||||
Fair value of notes payable | $ 302.0 |
Long-Term Debt - Schedule of Long-term Debt (Details) - USD ($) |
Dec. 31, 2016 |
Dec. 31, 2015 |
May 13, 2014 |
May 28, 2013 |
Dec. 04, 2012 |
---|---|---|---|---|---|
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $ 1,188,645,000 | $ 1,458,000,000 | |||
Unamortized discount on Second Lien Term Loans and Senior Notes | (12,802,000) | (17,604,000) | |||
Unamortized debt Issuance costs | (14,449,000) | (12,782,000) | |||
Total long term debt | 1,161,394,000 | 1,427,614,000 | |||
Second Lien Term Loans due 2020 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | 60,000,000 | 0 | |||
Senior notes | 8% Senior Notes due 2020 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $ 232,989,000 | 300,000,000 | $ 300,000,000 | ||
Stated interest rate | 8.00% | 8.00% | |||
Senior notes | 6.625% Senior Notes due 2021 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $ 432,656,000 | 550,000,000 | $ 300,000,000 | $ 250,000,000 | |
Stated interest rate | 6.625% | 6.625% | 6.625% | ||
Credit Facility due 2019 | |||||
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $ 463,000,000 | $ 608,000,000 |
Related Party Transactions (Details) - USD ($) |
1 Months Ended | 12 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2015 |
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
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President/CEO and Director, EVP, CDO | ||||
Related Party Transaction [Line Items] | ||||
Noncontrolling ownership interest in third party by related party | 4.16% | |||
Monthly rent expense | $ 111,299 | |||
Water Transfer Services | Blue Quail Energy Services, LLC | Board of Directors Chairman and Director | ||||
Related Party Transaction [Line Items] | ||||
Related party transaction amount | $ 98,297 | $ 382,629 | $ 84,470 | |
Reimbursement | Moriah Powder River LLC | Board of Directors Chairman and Director | ||||
Related Party Transaction [Line Items] | ||||
Related party transaction amount | $ 500,000 |
Commitments and Contingencies (Details) $ in Millions |
12 Months Ended |
---|---|
Dec. 31, 2016
USD ($)
$ / bbl
| |
Loss Contingencies [Line Items] | |
Purchase obligation, calculated floor price | $ / bbl | 57.14 |
Estimated total future purchase obligation | $ | $ 48.6 |
Officer | |
Loss Contingencies [Line Items] | |
Employment agreements with officers, severance pay consideration period, minimum | 24 months |
Employment agreements with officers, severance pay consideration period, maximum | 36 months |
Business and Credit Concentrations (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
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Risks and Uncertainties [Abstract] | |||
Bad debt expense | $ 0 | $ 0 | $ 0 |
Fair value of derivative transactions | $ 12,700,000 |
Derivative Financial Instruments - Schedule of Derivatives, Gain (Loss) on Derivative Activity (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward] | |||
Cash settlements paid | $ (64,505) | $ (132,925) | $ (2,666) |
Ending fair value of derivatives | 12,700 | ||
Interest rate swaps | Not designated as hedging instrument | |||
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward] | |||
Beginning fair value of derivatives | (362) | (2,080) | (4,759) |
Cash settlements paid | 2,653 | 3,266 | 3,230 |
Ending fair value of derivatives | 183 | (362) | (2,080) |
Interest rate swaps | Not designated as hedging instrument | Interest expense | |||
Realized and Unrealized Gains (Losses) Related to Derivatives [Roll Forward] | |||
Total loss on interest rate swaps | $ (2,108) | $ (1,548) | $ (551) |
Sales to Major Customers (Details) - Sales Revenue, Goods, Net - Customer Concentration Risk |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Enterprise (Teppco) Crude Oil, LP | |||
Concentration Risk [Line Items] | |||
Percentage of consolidated oil and natural gas revenue | 1.00% | 6.00% | 12.00% |
Plains Marketing, LP | |||
Concentration Risk [Line Items] | |||
Percentage of consolidated oil and natural gas revenue | 6.00% | 7.00% | 10.00% |
Asset Retirement Obligation (Details) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Changes in the ARO | |||
Asset retirement obligation — beginning of period | $ 286,405 | $ 226,525 | $ 175,786 |
Liabilities incurred with properties acquired | 24 | 60,526 | 50,487 |
Liabilities incurred with properties drilled | 1 | 92 | 941 |
Liabilities settled during the period | (2,351) | (2,615) | (2,918) |
Liabilities associated with properties sold | (24,605) | (9,386) | (5,891) |
Current period accretion | 12,674 | 11,263 | 8,120 |
Asset retirement obligation — end of period | $ 272,148 | $ 286,405 | $ 226,525 |
Asset Retirement Obligation Narrative (Details) - USD ($) |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Asset Retirement Obligation [Abstract] | |||
Revisions to previous estimates | $ 0 | $ 0 | $ 0 |
Unit-Based Compensation - Status of the Partnership's non-vested UARs (Details) - Unit appreciation rights (UARs) |
12 Months Ended |
---|---|
Dec. 31, 2016
$ / shares
shares
| |
Number of Units (in shares) | |
Non-vested at January 1, 2016 | shares | 566,067 |
Vested | shares | (221,387) |
Forfeited | shares | (30,503) |
Non-vested at December 31, 2016 | shares | 314,177 |
Weighted- Average Exercise Price (in dollars per share) | |
Non-vested at January 1, 2016 | $ / shares | $ 16.80 |
Vested | $ / shares | 20.14 |
Forfeited | $ / shares | 19.80 |
Non-vested at December 31, 2016 | $ / shares | $ 14.16 |
Unit-Based Compensation - Weighted Average Assumptions (Details) - Unit appreciation rights (UARs) - $ / shares |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2016 |
Dec. 31, 2015 |
Dec. 31, 2014 |
|
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Expected life (years) | 4 years 8 days | 4 years 10 months 28 days | 5 years 1 month 25 days |
Annual interest rate | 1.60% | 1.70% | 1.60% |
Annual distribution rate per unit (in dollars per share) | $ 0.00 | $ 0.60 | $ 2.44 |
Volatility | 87.00% | 59.00% | 38.00% |
Subsidiary Guarantors (Details) |
11 Months Ended | ||||
---|---|---|---|---|---|
May 08, 2014
offering
|
Dec. 31, 2016
USD ($)
|
Dec. 31, 2015
USD ($)
|
May 13, 2014
USD ($)
|
May 28, 2013
USD ($)
|
|
Debt Instrument [Line Items] | |||||
Long-term debt, gross | $ 1,188,645,000 | $ 1,458,000,000 | |||
Senior notes | 6.625% Senior Notes due 2021 | |||||
Debt Instrument [Line Items] | |||||
Number of private offerings | offering | 2 | ||||
Long-term debt, gross | $ 432,656,000 | $ 550,000,000 | $ 300,000,000 | $ 250,000,000 | |
Senior notes | 2020 and 2021 Senior Notes | |||||
Debt Instrument [Line Items] | |||||
Percent of guarantee by subsidiaries owned | 100.00% |
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