Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
RRC > SEC Filings for RRC > Form 10-Q on 28-Apr-2014All Recent SEC Filings

Show all filings for RANGE RESOURCES CORP

Form 10-Q for RANGE RESOURCES CORP


28-Apr-2014

Quarterly Report


ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. Certain sections of Management's Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements contain words such as "anticipates," "believes," "expects," "targets," "plans," "projects," "could," "may," "should," "would" or similar words indicating that future outcomes are uncertain. In accordance with "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. For additional risk factors affecting our business, see Item 1A. Risk Factors as set forth in our Annual Report on Form 10-K for the year ended December 31, 2013, as filed with the SEC on February 26, 2014.

Overview of Our Business

We are a Fort Worth, Texas-based independent natural gas, natural gas liquids ("NGLs") and oil company primarily engaged in the exploration, development and acquisition of natural gas and oil properties in the Appalachian and Southwestern regions of the United States. We operate in one segment and have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area.

Our objective is to build stockholder value through consistent growth in reserves and production on a cost-efficient basis. Our strategy to achieve our objective is to increase reserves and production through internally generated drilling projects occasionally coupled with complementary acquisitions. Our revenues, profitability and future growth depend substantially on prevailing prices for natural gas, NGLs, crude oil and condensate and on our ability to economically find, develop, acquire and produce natural gas, NGLs and crude oil reserves. Prices for natural gas, NGLs and oil fluctuate widely and affect:

- the amount of cash flows available for capital expenditures;

- our ability to borrow and raise additional capital; and

- the quantity of natural gas, NGLs and oil we can economically produce.

We prepare our financial statements in conformity with generally accepted accounting principles, which require us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved natural gas, NGLs and oil reserves. We use the successful efforts method of accounting for our natural gas, NGLs and oil activities.

Market Conditions

Prices for our products significantly impact our revenue, net income and cash
flow. Natural gas, NGLs and oil are commodities and prices for commodities are
inherently volatile. The following table lists average New York Mercantile
Exchange ("NYMEX") prices for natural gas and oil and the Mont Belvieu NGL
composite price for the three months ended March 31, 2014 and 2013:

                                                      Three Months Ended
                                                           March 31,
                                                       2014          2013
          Average NYMEX prices (a)
          Natural gas (per mcf)                     $     4.89      $  3.35
          Oil (per bbl)                             $    98.61      $ 94.25
          Mont Belvieu NGL Composite (per gallon)   $     0.91      $  0.78

(a) Based on weighted average of bid week prompt month prices.

Consolidated Results of Operations

Overview of First Quarter 2014 Results

During first quarter 2014, we achieved the following financial and operating results:

- increased revenue from the sale of natural gas, NGLs and oil by 44% from the same period of 2013;



- achieved 21% production growth over the same period of 2013;

- continued expansion of our activities in the Marcellus Shale in Pennsylvania by growing production, proving up acreage and acquiring additional unproved acreage;

- excluding workovers, our direct operating expenses per mcfe remained flat from the same period of 2013;

- reduced our depletion, depreciation and amortization ("DD&A") rate 8% over the same period of 2013;

- entered into additional derivative contracts for 2014, 2015 and 2016; and

- realized $181.2 million of cash flow from operating activities.

Our first quarter 2014 net income was $32.5 million, or $0.20 per diluted common share compared to a net loss of $75.6 million, or a loss of $0.47 per diluted common share in the same period 2013. During first quarter 2014, we had an increase in revenue from the sale of natural gas, NGLs and oil driven by higher production volumes of 21%. Our first quarter 2014 production growth was due to the continued success of our drilling program, particularly in the Marcellus Shale. First quarter 2014 production for NGLs increased 137% from the same period of 2013 due to our sales of ethane based on our new ethane sales/transport agreements which commenced initial deliveries in late 2013. When comparing first quarter 2014 to the same period of 2013, we also experienced a favorable increase in our non-cash mark-to-market related to our deferred compensation plans along with favorable non-cash fair value adjustments on our commodity derivatives, a non-GAAP measure and lower general and administrative expense, all of which were somewhat offset by lower realized prices. Realized prices include the impact of basis differentials. Average natural gas differentials were $0.66 per mcf above NYMEX in the first quarter 2014 compared to $0.15 per mcf above NYMEX in the same quarter 2013. This increase was more than offset by realized losses on our basis hedging in the first quarter 2014 of $0.90 per mcfe.

We believe natural gas, NGLs and oil prices will remain volatile and will be affected by, among other things, weather, the U.S. and worldwide economy, new technology and the level of oil and gas production in North America and worldwide. Although we have entered into derivative contracts covering a portion of our production volumes for the remainder of 2014 and for 2015 and 2016, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.

Natural Gas, NGLs and Oil Sales, Production and Realized Price Calculations

Our revenues vary primarily as a result of changes in realized commodity prices, production volumes and the value of certain of our derivative contracts. We generally sell natural gas, NGLs and oil under two types of agreements, which are common in our industry. Revenue from the sale of natural gas, NGLs and oil sales include netback arrangements where we sell natural gas and oil at the wellhead and collect a price, net of transportation incurred by the purchaser. In this instance, we record revenue at the price we receive from the purchaser. Revenues are also realized from sales arrangements where we sell natural gas or oil at a specific delivery point and receive proceeds from the purchaser with no transportation deduction. Third party transportation costs we incur to get our commodity to the delivery point are reported in transportation, gathering and compression expense. Hedges included in natural gas, NGLs and oil sales reflect settlements on those derivatives that qualified for hedge accounting. Cash settlements and changes in the market value of derivative contracts that are not accounted for as hedges are included in derivative fair value income or loss in the statement of operations. For more information on revenues from derivative contracts that are not accounted for as hedges, see the derivative fair value loss discussion below. Effective March 1, 2013, we elected to de-designate all commodity contracts that were previously designated as cash flow hedges and elected to discontinue hedge accounting prospectively. Refer to Note 11 to the consolidated financial statements for more information.


In first quarter 2014, natural gas, NGLs and oil sales increased 44% compared to the same period of 2013 with a 21% increase in production and a 19% increase in realized prices. The following table illustrates the primary components of natural gas, NGLs, crude oil and condensate sales for the three months ended March 31, 2014 and 2013 (in thousands):

                                                     Three Months Ended March 31,
                                            2014           2013          Change      % Change
Natural gas, NGLs and oil sales
Gas wellhead                             $  346,226     $  217,088     $  129,138           59 %
Gas hedges realized (a)                       1,168         35,478        (34,310 )        (97 %)
Total gas revenue                        $  347,394     $  252,566     $   94,828           38 %
Total NGLs revenue                       $  135,504     $   67,571     $   67,933          101 %
Oil and condensate wellhead              $   88,121     $   77,080     $   11,041           14 %
Oil hedges realized (a)                         998          1,022            (24 )         (2 %)
Total oil and condensate revenue         $   89,119     $   78,102     $   11,017           14 %
Combined wellhead                        $  569,851     $  361,739     $  208,112           58 %
Combined hedges (a)                           2,166         36,500        (34,334 )        (94 %)
Total natural gas, NGLs and oil sales    $  572,017     $  398,239     $  173,778           44 %

(a) Cash settlements related to derivatives that qualified or were historically designated for hedge accounting.

Our production continues to grow through drilling success as we place new wells on production partially offset by the natural decline of our natural gas and oil wells and asset sales. When compared to the same period of 2013, our first quarter 2014 production volumes increased 25% in our Appalachian region and decreased 5% in our Southwestern region. When compared to the same period of 2013, our Marcellus production volumes increased 29% for the first quarter. The decline in natural gas production volumes is primarily related to the increased sales of ethane, the extraction of which reduces natural gas volumes to be sold and, to a lesser extent, adverse weather conditions during first quarter 2014. Ethane production volumes are reported with NGLs in the table below. Our production for the three months ended March 31, 2014 and 2013 is set forth in the following table:

                                                          Three Months Ended March 31,
                                          2014              2013            Change              % Change
Production (a)
Natural gas (mcf)                        62,017,581       62,023,956           (6,375   )           %
NGLs (bbls)                               4,471,481        1,889,424        2,582,057             151 %
Crude oil and condensate (bbls)           1,035,145          912,662          122,483              13 %
Total (mcfe) (b)                         95,057,337       78,836,472       16,220,865              21 %
Average daily production (a)
Natural gas (mcf)                           689,084          689,155              (71   )           %
NGLs (bbls)                                  49,683           20,994           28,689             137 %
Crude oil and condensate (bbls)              11,502           10,141            1,361              13 %
Total (mcfe) (b)                          1,056,193          875,961          180,232              21 %

(a) Represents volumes sold regardless of when produced.

(b) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not necessarily indicative of the relationship between oil and natural gas prices.


Our average realized price (including all derivative settlements and third-party transportation costs) received during first quarter 2014 was $4.14 per mcfe compared to $4.26 per mcfe in the same period of 2013. Because we record transportation costs on two separate bases, as required by U.S. GAAP, we believe computed final realized prices should include the total impact of transportation, gathering and compression expense. Our average realized price
(including all derivative settlements and third-party transportation costs)
calculation also includes all cash settlements for derivatives, whether or not they qualified for hedge accounting. Average sales prices (wellhead) do not include derivative settlements or third party transportation costs which are reported in transportation, gathering and compression expense on the accompanying statements of operations. Average sales prices (wellhead) do include transportation costs where we receive net revenue proceeds from purchasers. Average realized price calculations for the three months ended March 31, 2014 and 2013 are shown below:

                                                       Three Months Ended
                                                           March 31,
                                                      2014            2013
        Average Prices
        Average sales prices (wellhead):
        Natural gas (per mcf)                      $      5.58     $     3.50
        NGLs (per bbl)                                   30.30          35.76
        Crude oil and condensate (per bbl)               85.13          84.46
        Total (per mcfe) (a)                              5.99           4.59
        Average realized prices (including
        derivative settlements that qualified
        for hedge accounting):
        Natural gas (per mcf)                      $      5.60     $     4.07
        NGLs (per bbl)                                   30.30          35.76
        Crude oil and condensate (per bbl)               86.09          85.58
        Total (per mcfe) (a)                              6.02           5.05
        Average realized prices (including all
        derivative settlements):
        Natural gas (per mcf)                      $      4.20     $     4.09
        NGLs (per bbl)                                   27.34          35.29
        Crude oil and condensate (per bbl)               82.03          85.46
        Total (per mcfe) (a)                              4.92           5.06
        Average realized prices (including all
        derivative settlements and third party
        transportation costs paid by Range):
        Natural gas (per mcf)                      $      3.14     $     3.14
        NGLs (per bbl)                                   25.35          33.61
        Crude oil and condensate (per bbl)               82.03          85.46
        Total (per mcfe) (a)                              4.14           4.26

(a) Oil and NGLs are converted to mcfe at the rate of one barrel equals six mcf based upon the approximate relative energy content of oil to natural gas, which is not indicative of the relationship between oil and natural gas prices.

Derivative fair value loss was $146.9 million in first quarter 2014 compared to $99.9 million in the same period of 2013. Through February 28, 2013, some of our derivatives did not qualify for hedge accounting and were accounted for using the mark-to-market accounting method whereby all realized and unrealized gains and losses related to these contracts are included in derivative fair value income or loss in the accompanying consolidated statements of operations. Effective March 1, 2013, we discontinued hedge accounting prospectively. Since March 1, 2013, all of our derivatives are accounted for using the mark-to-market accounting method. Mark-to-market accounting treatment results in volatility of our revenues as unrealized gains and losses from derivatives are included in total revenue. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.

Loss on the sale of assets was $353,000 in first quarter 2014 compared to a loss of $166,000 in the same period of 2013. In first quarter 2014 and 2013, we sold miscellaneous proved and unproved oil and gas properties and inventory for proceeds received of $294,000 in first quarter 2014 compared to $38.2 million in the same period of 2013.

Brokered natural gas, marketing and other revenue in first quarter 2014 was $32.5 million compared to $21.0 million in the same period of 2013. The first three months 2014 includes a loss from equity method investments of $133,000 and $33.2 million of revenue from marketing and the sale of brokered gas. The first three months 2013 includes loss from equity method investments of $80,000 and $21.1 million of revenue from marketing and the sale of brokered gas. These revenues increased due to an increase in brokered volumes.


We believe some of our expense fluctuations are best analyzed on a unit-of-production, or per mcfe, basis. The following presents information about certain of our expenses on a per mcfe basis for the three months ended March 31, 2014 and 2013:

                                                  Three Months Ended March 31,
                                                           (per mcfe)
                                                                                      %
                                        2014           2013          Change         Change
Direct operating expense             $     0.42     $     0.38     $     0.04            11 %
Production and ad valorem tax
expense                                    0.12           0.14          (0.02 )         (14 %)
General and administrative expense         0.52           1.07          (0.55 )         (51 %)
Interest expense                           0.48           0.54          (0.06 )         (11 %)
Depletion, depreciation and
amortization expense                       1.35           1.46          (0.11 )          (8 %)

Direct operating expense was $39.8 million in first quarter 2014 compared to $30.2 million in the same period of 2013. We experience increases in operating expenses as we add new wells and manage existing properties. Direct operating expenses include normally recurring expenses to operate and produce our wells, non-recurring well workovers and repair-related expenses. Our production volumes increased 21% but, on an absolute basis, our spending for direct operating expenses for first quarter 2014 increased 32% with an increase in the number of producing wells, higher workover costs, higher water handling and winter operations costs somewhat offset by the sale of certain non-core assets at the beginning of second quarter 2013. We incurred $5.6 million of workover costs in first quarter 2014 compared to $1.4 million of workover costs in the same period of 2013.

On a per mcfe basis, direct operating expense in first quarter 2014 increased 11% from the same period of 2013 with the increase consisting of higher workover costs. We expect to experience lower costs per mcfe as we increase production from our Marcellus Shale wells due to their lower operating cost relative to our other operating areas. However, our operating costs in the Mississippian play are higher on a per mcfe basis than the Marcellus Shale play. As production increases from the Mississippian play, our direct operating expenses per mcfe are expected to increase. The following table summarizes direct operating expenses per mcfe for the three months ended March 31, 2014 and 2013:

                                                   Three Months Ended March 31,
                                                            (per mcfe)
                                                                                   %
                                             2014         2013      Change       Change
     Lease operating expense               $    0.35     $ 0.35     $                  %
     Workovers                                  0.06       0.02        0.04          200 %
     Stock-based compensation (non-cash)        0.01       0.01                        %
     Total direct operating expense        $    0.42     $ 0.38     $  0.04           11 %

Production and ad valorem taxes are paid based on market prices, not hedged prices. This expense category also includes the Pennsylvania impact fee that was initially assessed in 2012. Production and ad valorem taxes (excluding the impact fee) were $5.2 million in first quarter 2014 compared to $4.2 million in the same period of 2013. On a per mcfe basis, production and ad valorem taxes (excluding the impact fee) was $0.05 in both first quarter 2014 and first quarter 2013 with an increase in volumes not subject to production taxes more than offset by higher prices. In February 2012, the Commonwealth of Pennsylvania enacted an "impact fee" on unconventional natural gas and oil production which includes the Marcellus Shale. Included in first quarter 2014 is a $6.5 million impact fee ($0.07 per mcfe) compared to $7.1 million ($0.09 per mcfe) in the same period of the prior year.


General and administrative ("G&A") expense was $49.2 million in first quarter 2014 compared to $84.1 million for the same period of 2013. The first quarter 2014 decrease of $34.8 million when compared to 2013 is primarily due to lower lawsuit settlements. The first quarter 2013 included an accrual of $35.0 million related to an Oklahoma lawsuit that was settled in second quarter 2013 for $87.5 million. Stock-based compensation expense represents the amortization of restricted stock grants and performance shares granted to our employees and non-employee directors as part of compensation. On a per mcfe basis, G&A expense decreased 51% from first quarter 2013 primarily due to the settlement of the Oklahoma lawsuit which was partially accrued in first quarter 2013 and lower salaries and benefits. The following table summarizes general and administrative expenses per mcfe for the three months ended March 31, 2014 and 2013:

                                                      Three Months Ended March 31,
                                                               (per mcfe)
                                                                                      %
                                               2014        2013       Change       Change
  General and administrative                  $  0.40     $ 0.50     $  (0.10 )        (20 %)
  Oklahoma legal settlement                                0.44        (0.44 )       (100 %)
  Stock-based compensation (non-cash)            0.12       0.13        (0.01 )         (8 %)
  Total general and administrative expenses   $  0.52     $ 1.07        (0.55 )        (51 %)

Interest expense was $45.4 million for first quarter 2014 compared to $42.2 million for first quarter 2013. The following table presents information about interest expense per mcfe for the three months ended March 31, 2014 and 2013:

                                                    Three Months Ended March 31,
                                                             (per mcfe)
                                                                                        %
                                          2014           2013          Change         Change
Bank credit facility                   $     0.05     $     0.06     $    (0.01 )         (17 %)
Subordinated notes                           0.41           0.45          (0.04 )          (9 %)
Amortization of deferred financing
costs and other                              0.02           0.03          (0.01 )         (33 %)
Total interest expense                 $     0.48     $     0.54          (0.06 )         (11 %)

On an absolute basis, the increase in interest expense for first quarter 2014 from the same period of 2013 was primarily due to an increase in outstanding debt balances. In March 2013, we issued $750.0 million of 5.0% senior subordinated notes due 2023. We used the proceeds to repay our outstanding bank debt which carries a lower interest rate. We used the proceeds to repay $350.0 million of our outstanding credit facility balance and for general corporate purposes. The 2013 note issuance was undertaken to better match the maturities of our debt with the life of our properties and to give us greater liquidity for the near term. Average debt outstanding on the bank credit facility for first quarter 2014 was $611.8 million compared to $685.6 million in the same period of 2013 and the weighted average interest rate on the bank credit facility was 2.0% in first quarter 2014 compared to 2.1% in the same period of 2013.

Depletion, depreciation and amortization ("DD&A") was $128.7 million in first quarter 2014 compared to $115.1 million in the same period of 2013. The increase in first quarter 2014 when compared to the same period of 2013 is due to a 7% decrease in depletion rates more than offset by a 21% increase in production. Depletion expense, the largest component of DD&A, was $1.28 per mcfe in first quarter 2014 compared to $1.38 per mcfe in the same period of 2013. We have historically adjusted our depletion rates in the fourth quarter of each year based on the year-end reserve report and other times during the year when circumstances indicate there has been a significant change in reserves or costs. Our depletion rate per mcfe continues to decline due to our drilling success in the Marcellus Shale. The following table summarizes DD&A expense per mcfe for the three months ended March 31, 2014 and 2013:

                                              Three Months Ended March 31,
                                                       (per mcfe)
                                                                              %
                                       2014        2013       Change        Change
         Depletion and amortization   $  1.28     $ 1.38     $  (0.10 )          (7 %)
         Depreciation                    0.03       0.05        (0.02 )         (40 %)
         Accretion and other             0.04       0.03         0.01            33 %
         Total DD&A expense           $  1.35     $ 1.46     $  (0.11 )          (8 %)


. . .
  Add RRC to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for RRC - All Recent SEC Filings
Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.