美國
證券和交易委員會
華盛頓特區 20549
表格
（標記一）
截至季度結束日期的財務報告
or
過渡期從 到
委託文件編號：001-39866
(根據其章程規定的註冊人準確名稱)
公司的註冊和其他管轄範圍 組織) |
（內部稅務服務僱主識別號碼） |
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(主要領導機構的地址) |
(郵政編碼) |
(
(註冊人電話號碼，包括區號)
不適用
（前名稱、地址及財政年度，如果自上次報告以來有更改）
在法案第12(b)條的規定下注冊的證券：
每個類別的標題
|
交易標的
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在其上註冊的交易所的名稱
|
該 |
請在以下方框內打勾，以指示註冊人是否（1）已在過去12個月內（或在註冊人需要提交此類報告的較短期間內）提交了交易所法案第13或15（d）條規定的所有要求提交的報告，並且（2）在過去90天內一直需要遵守提交要求。
☑ 否 ☐
請在勾選標誌處表示註冊人是否已經在過去12個月內（或者在註冊人要求提交這些文件的較短時期內）按照規則405 of協議S-T（本章節的§232.405）提交了每個交互式數據文件。 ☒ 沒有 ☐
請勾選圓圈以表示公司的註冊人是否爲大型加速報告公司、加速報告公司、非加速報告公司、小型報告公司或新興成長公司。有關「大型加速報告公司」、「加速報告公司」、「小型報告公司」和「新興成長公司」的定義，請參見《交易所法規》第120億.2條。
大型加速報告人 |
☐ |
☒ |
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非加速文件提交人 |
☐ |
較小的報告公司 |
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新興成長公司 |
如果公司無法符合證券交易法第13(a)條規定，使用延長過渡期來遵守任何新的或修訂的財務會計準則，請在複選框中指示。
請在檢查標記處說明申報人是否爲外殼公司 (見交易所法案 Rule 12b-2 定義)。 是☐ 沒有
截至2024年11月8日，註冊公司普通股的流通股數量爲
目錄 內容
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頁面 |
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6 |
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項目 1. |
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6 |
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項目 2. |
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27 |
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項目 3. |
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49 |
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項目 4. |
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49 |
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50 |
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項目 1. |
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50 |
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項目1A. |
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50 |
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項目 2. |
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50 |
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項目 3. |
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50 |
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項目 4. |
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50 |
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第5項 |
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50 |
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項目6。 |
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51 |
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52 |
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```
Glossary of Key Terms
本季度報告表格10-Q使用了多個特定於我們行業和業務的術語。爲了方便讀者，在此提供了相關術語的詞彙表。除非我們另有說明，或除非上下文另有要求，本季度報告表格10-Q中對以下內容的任何引用：
3
關於前瞻性聲明的警告
本季度報告表格10-Q包含美國聯邦證券法意義上的「前瞻性聲明」，這些聲明涉及重大風險和不確定性。本報告中包含的所有除歷史或當前事實聲明以外的聲明均爲前瞻性聲明。前瞻性聲明指的是我們關於財務狀況、運營結果、計劃、目標、戰略、未來表現和業務的當前預期和預測。前瞻性聲明可能包括諸如「預期」、「假定」、「相信」、「可以有」、「考慮」、「繼續」、「努力」、「目標」、「可能」、「設計」、「由於」、「估計」、「期待」、「預測」、「目標」、「打算」、「可能」、「可能」、「目標」、「計劃」、「預測」、「項目」、「潛力」、「尋求」、「應該」、「目標」、「將」、「會」等詞彙及其他在任何討論未來運營表現或其他事件的時間或性質時具有類似含義的詞彙。例如，所有與我們未來的運營結果、財務狀況、預期和計劃相關的聲明，包括涉及北卡羅來納州Montauk Ag項目、第二個Apex RNG設施、Blue Granite RNG設施、Bowerman RNG設施、將生物源二氧化碳量交付給歐洲能源、Emvolon合作及實驗項目、McCarty設施的燃料收集問題解決、填埋場主井場擴展項目的延遲和取消、Rumpke和Apex設施的井場提取環保母基因素緩解、我們如何將RNG生產貨幣化以及氣候相關異常的聲明均爲前瞻性聲明。所有前瞻性聲明均面臨風險和不確定性，可能導致實際結果與我們預期的結果存在實質性差異，因此，你不應過分依賴這些聲明。可能導致實際結果與這些前瞻性聲明所表達或暗示的結果存在實質性差異的風險和不確定性包括但不限於：
4
我們根據我們的經營預算和預測制定了許多前瞻性聲明，這些聲明基於詳細的假設。雖然我們認爲我們的假設是合理的，但我們警告稱，預測已知因素的影響是非常困難的，我們不可能預測所有可能影響我們實際結果的因素。
所有歸屬於我們的前瞻性聲明在其整體上均受到這些警告性聲明以及我們在美國證券交易委員會（「SEC」）備案的其他文件和公開通信中所作其他聲明的明確約束。您應在這些風險和不確定性的背景下評估我們所作的所有前瞻性聲明。請參閱我們最新的10-k表格年度報告中的「風險因素」部分以及我們在SEC的其他備案文件。
我們提醒您，我們所識別的風險和不確定性可能並不包含對您重要的所有因素。此外，本報告中包含的前瞻性陳述僅在此日期作出。除法律要求外，我們不承擔因新信息、未來事件或其他原因而公開更新或修訂任何前瞻性陳述的義務。
5
第一部分財務信息
項目 1。 基本報表
|
頁面 |
Montauk Renewables, Inc. |
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未經審計的精簡合併財務報表 |
|
7 |
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8 |
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9 |
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10 |
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11 |
6
蒙太克可再生能源公司
鞏固經簡化後的資產負債表
(未經審計)
（以千爲單位，除共享數據外）：
|
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截至9月30日, |
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截至2023年12月31日， |
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資產 |
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2024 |
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2023 |
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流動資產： |
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現金及現金等價物 |
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$ |
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$ |
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應收賬款及其他應收款項 |
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當前受限現金 |
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9,065 |
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預付費用及其他流動資產 |
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總流動資產 |
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$ |
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$ |
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非流動限制現金 |
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$ |
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$ |
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物業、廠房和設備，淨值 |
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商譽和無形資產，淨值 |
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遞延稅款資產 |
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衍生金融工具的非流動部分 |
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經營租賃使用權資產 |
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融資租賃使用權資產 |
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關聯方應收款 |
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其他資產 |
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總資產 |
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$ |
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$ |
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負債和股東權益 |
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流動負債: |
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應付賬款 |
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$ |
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$ |
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應計負債 |
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應交所得稅 |
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當前運營租賃負債部分 |
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融資租賃負債的當前部分 |
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長期債務的流動部分 |
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總流動負債 |
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$ |
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$ |
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長期債務，減去當期部分 |
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$ |
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$ |
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經營租賃負債的非流動部分 |
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融資租賃負債的非流動部分 |
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資產養老責任 |
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其他負債 |
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總負債 |
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$ |
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$ |
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(註釋20) |
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股東權益 |
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普通股，每股面值爲 $0.0001； |
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$ |
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$ |
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截至2024年3月31日和2023年12月31日，公司的庫藏股票分別有2,279,784股和2,693,653股。 |
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( |
) |
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( |
) |
追加實收資本 |
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留存收益 |
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股東權益總額 |
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$ |
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$ |
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負債和股東權益合計 |
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$ |
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$ |
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未經審計的簡明合併基本報表附註是這些報表的一部分。
7
蒙太克可再生能源公司
綜合財務報表經營狀況表
(未經審計)
(以千爲單位，除分享和每股數據外):
|
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三個月 |
在這九個月中 |
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2024 |
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2023 |
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2024 |
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2023 |
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總營收 |
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$ |
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$ |
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$ |
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$ |
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運營費用： |
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營運和維護費用 |
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一般和行政費用 |
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版稅、運輸、集油和生產燃料 |
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折舊、衰減和攤銷 |
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減值損失 |
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交易成本 |
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— |
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— |
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總營業費用 |
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$ |
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$ |
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$ |
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$ |
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營業收入 |
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$ |
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$ |
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$ |
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$ |
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其他費用（收入）: |
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利息支出 |
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$ |
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$ |
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$ |
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$ |
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其他收入 |
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( |
) |
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( |
) |
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( |
) |
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( |
) |
其他支出總額 |
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$ |
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$ |
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$ |
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$ |
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稅前收入 |
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$ |
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$ |
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$ |
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$ |
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所得稅費用 |
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淨利潤 |
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$ |
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$ |
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$ |
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$ |
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每股收益： |
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基本 |
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$ |
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$ |
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$ |
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$ |
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攤薄 |
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$ |
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$ |
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$ |
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$ |
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加權平均流通普通股數量： |
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基本 |
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攤薄 |
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未經審計的簡明合併基本報表附註是這些報表的一部分。
8
蒙塔克可再生能源公司
合併財務報表股東權益變動表
(未經審計)
（以千爲單位，除共享數據外）：
|
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普通股 |
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自家保管的股票 |
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股份 |
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金額 |
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股份 |
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金額 |
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追加實收資本 |
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留存收益 |
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總股本 |
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2024年6月30日餘額 |
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$ |
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$ |
( |
) |
|
$ |
|
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$ |
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$ |
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||||||
普通股發行 |
|
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— |
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— |
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— |
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— |
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自家保管的股票 |
|
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— |
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— |
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( |
) |
|
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— |
|
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— |
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( |
) |
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淨利潤 |
|
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— |
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— |
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— |
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— |
|
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— |
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基於股票的補償 |
|
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— |
|
|
|
— |
|
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— |
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— |
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— |
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2024年9月30日的結餘 |
|
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$ |
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$ |
( |
) |
|
$ |
|
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$ |
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$ |
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2023年6月30日的餘額 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
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||||||
股票獎勵的解禁 |
|
|
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|
|
— |
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|
|
— |
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|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
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淨利潤 |
|
|
— |
|
|
|
— |
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|
|
— |
|
|
|
— |
|
|
|
— |
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基於股票的補償 |
|
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— |
|
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— |
|
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— |
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— |
|
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|
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— |
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||
2023年9月30日的餘額 |
|
|
|
|
$ |
|
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|
|
|
$ |
( |
) |
|
$ |
|
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$ |
|
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$ |
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||||||
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2023年12月31日餘額 |
|
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|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
普通股發行 |
|
|
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|||
自家保管的股票 |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
|
淨利潤 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
基於股票的補償 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
2024年9月30日的結餘 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
2022年12月31日的餘額 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
股票獎勵的解禁 |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
淨利潤 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
基於股票的補償 |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
||
2023年9月30日的餘額 |
|
|
|
|
$ |
|
|
|
|
|
$ |
( |
) |
|
$ |
|
|
$ |
|
|
$ |
|
||||||
未經審計的簡明合併基本報表附註是這些報表的一部分。
9
蒙太克可再生能源公司
合併現金流量表
(未經審計)
（以千爲單位）：
|
|
截至九月三十日止九個月。 |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
經營活動現金流量： |
|
|
|
|
|
|
||
淨利潤 |
|
$ |
|
|
$ |
|
||
調整淨利潤爲經營活動提供的淨現金流量 |
|
|
|
|
|
|
||
折舊、衰減和攤銷 |
|
|
|
|
|
|
||
遞延所得稅費用 |
|
|
|
|
|
|
||
基於股票的補償 |
|
|
|
|
|
|
||
衍生品公允價值調整及結算 |
|
|
|
|
|
( |
) |
|
資產出售淨損失 |
|
|
|
|
|
|
||
(減少) 增加盈利責任 |
|
|
( |
) |
|
|
|
|
資產退休責任增值 |
|
|
|
|
|
|
||
與已售物業相關的負債 |
|
|
( |
) |
|
|
|
|
債務發行成本的攤銷 |
|
|
|
|
|
|
||
減值損失 |
|
|
|
|
|
|
||
運營資產和負債的變化： |
|
|
|
|
|
|
||
應收賬款及其他應收款和其他流動資產 |
|
|
( |
) |
|
|
( |
) |
|
|
|
|
|
|
|
||
經營活動產生的淨現金流量 |
|
$ |
|
|
$ |
|
||
投資活動現金流量： |
|
|
|
|
|
|
||
資本支出 |
|
$ |
( |
) |
|
$ |
( |
) |
資產收購 |
|
|
( |
) |
|
|
|
|
現金擔保存款 |
|
|
|
|
|
|
||
投資活動中使用的淨現金 |
|
$ |
( |
) |
|
$ |
( |
) |
融資活動的現金流： |
|
|
|
|
|
|
||
長期負債還款 |
|
$ |
( |
) |
|
$ |
( |
) |
普通股發行 |
|
|
|
|
|
|
||
庫存股票購買 |
|
|
( |
) |
|
|
|
|
融資租賃支付 |
|
|
( |
) |
|
|
( |
) |
融資活動所使用的淨現金 |
|
$ |
( |
) |
|
$ |
( |
) |
現金及現金等價物和受限制的現金淨減少額 |
|
$ |
( |
) |
|
$ |
( |
) |
期初的現金及現金等價物和受限制的現金 |
|
$ |
|
|
$ |
|
||
期末現金及現金等價物和受限現金 |
|
$ |
|
|
$ |
|
||
截至期末的現金、現金及現金等價物和受限現金的對賬 |
|
|
|
|
|
|
||
現金及現金等價物 |
|
$ |
|
|
$ |
|
||
限制使用的現金及現金等價物 - 目前 |
|
|
|
|
|
|
||
受限現金及現金等價物 - 非流動 |
|
|
|
|
|
|
||
|
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
||
補充現金流量信息： |
|
|
|
|
|
|
||
支付的利息現金 |
|
$ |
|
|
$ |
|
||
支付的所得稅費用 |
|
|
|
|
|
|
||
包括在應付帳款中的固定資產購置應計費用 |
|
|
|
|
|
|
||
未經審計的簡明合併基本報表附註是這些報表的一部分。
10
蒙太克可再生能源公司
未經審計的基本財務報表附註
(以千美元計，除每股金額外)
附註 1 — 業務描述
運營和組織
蒙托克可再生能源的業務
蒙托克可再生能源公司（「公司」 或 「蒙托克可再生能源」）是一家可再生能源公司，專門從事沼氣的管理、回收和轉化爲可再生天然氣（「RNG」）。該公司捕獲甲烷，防止其釋放到大氣中，並將其轉化爲可再生天然氣或電網的電力（「可再生髮電」 或 「REG」）。該公司總部位於賓夕法尼亞州匹茲堡，擁有超過
該公司的兩個主要收入驅動因素是生產的天然氣的銷售和向燃料調配商銷售可再生識別碼（「RIN」）。可再生燃料標準（「RFS」）是環境保護署（「EPA」）管理的聯邦法律，要求運輸燃料中含有最低體積的可再生燃料。源自垃圾填埋場甲烷、農業沼氣池和用作車輛燃料的廢水處理設施的 RNG 符合 D3（纖維素生物燃料，具有
該公司使用的另一項計劃是低碳燃料標準（「LCFS」）。這是各州特有的，旨在刺激低碳燃料的使用。如果公司設施中的隨機天然氣在已採用LCFS計劃的州被用作運輸燃料，則有資格獲得聯邦RFS規定的RIN值之外的環境屬性。
另一個關鍵的收入驅動因素是發電的銷售以及與電力銷售相關的相關環境溢價。該公司的電力設施旨在符合各州的可再生能源投資組合標準並從中獲利，該標準要求該州生產的一定比例的電力來自可再生資源。此類保費以可再生能源信貸（「REC」）的形式出現。作爲購買電力協議的一部分，該公司最大的電力設施位於加利福尼亞州，通過REC的貨幣化獲得收入。
注2-重要會計政策摘要
做法的基礎
11
分部報告
該公司在中報告分部信息
可再生天然氣板塊代表以固定價格合約出售的天然氣的銷售、可再生天然氣交易量的交易對手份額和適用的環境屬性。該業務部門佔公司收入的大部分。可再生髮電板塊代表發電的銷售和適用的環境屬性。
公司與公司職能的其他離散財務信息有關。它主要用作共享服務中心，用於維護行政、會計、財務、法律、人力資源、稅務、環境、工程和其他未以其他方式分配給細分市場的運營職能。因此，公司分部未被確定爲運營板塊，而是爲了與公司的合併財務報表進行對賬而單獨披露。
估算值的使用
根據公認會計原則編制財務報表要求管理層做出估算和假設，這些估計和假設會影響財務報表日報告的資產負債金額和或有資產負債的披露以及報告期內報告的收入和支出金額。實際結果可能與這些估計有所不同。
最近發佈的會計準則
2020年3月，財務會計準則委員會發布了ASU第2020-04號《參考利率改革》（主題848），爲當前合同修改和套期保值關係指南提供了可選的權宜之計和例外情況，以減輕預期的市場從倫敦銀行同業拆借利率（「LIBOR」）和其他銀行同業拆借利率向替代參考利率過渡的財務報告負擔。該指南自發布之日起生效，可能適用於2022年12月31日當天或之前做出的合同修改以及簽訂或評估的對沖關係。FasB根據對倫敦銀行同業拆借利率何時停止發佈的預期，在主題848中納入了日落條款。日落條款已從2022年12月31日至2024年12月31日進行了修訂，之後將不再允許實體在主題848中申請救濟。該公司目前的債務協議按彭博短期銀行收益率指數 「BSBY」 計息，外加適用的利潤。BSBY指數將於2024年11月15日停止，目前的債務協議已經過修訂，使用有擔保隔夜融資利率指數 「SOFR」，外加適用的利潤。
2023 年 11 月，財務會計準則委員會發布了亞利桑那州立大學第 2023-07 號《分部報告（主題 280）：可報告細分市場的改進》。2023-07年的修正案旨在改善可申報的分部披露要求，主要是通過加強對重大分部支出的披露。亞利桑那州立大學2023-07對公司截至2024年12月31日止年度的10-k表年度報告及隨後的過渡期有效，允許提前採用。除了加強披露外，公司預計該準則的採用不會對其合併財務報表產生重大影響。
2023年12月，財務會計準則委員會發布了亞利桑那州立大學第2023-09號《所得稅（主題740）：所得稅披露的改進》。2023-09年的修正案旨在提高所得稅披露的透明度和決策實用性。亞利桑那州立大學2023-09年度對公司截至2025年12月31日止年度的10-k表年度報告有效，允許提前採用。除了加強披露外，公司預計該準則的採用不會對其合併財務報表產生重大影響。
NOTE 3 – ASSET IMPAIRMENT
The Company recorded an impairment loss of $
12
sites. The 2023 impairments were for specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in the Company's RNG segment.
NOTE 4 – REVENUES FROM CONTRACTS WITH CUSTOMERS
The Company’s revenues are comprised of renewable energy and related Environmental Attribute sales provided under short and medium term contracts with its customers. All revenue is recognized when (or as) the Company satisfies its performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product or service to its customer either when (or as) its customer obtains control of the product or service. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. The Company allocates the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.
Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring its products or services. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred by the customer following the transfer of control of the commodities sold. To the extent applicable, sales, value add and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.
The Company’s performance obligations related to the sale of renewable energy (i.e. RNG and Renewable Electricity Generation) are generally satisfied over time. Revenue related to the sale of renewable energy is generally recognized over time using an output based upon the product quantity delivered to the customer. This measure is used to best depict the Company’s performance to date under the terms of the contract. Revenue from products transferred to customers over time accounted for approximately
The nature of the Company’s contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the contracts is considered fully constrained.
The Company’s performance obligations related to the sale of Environmental Attributes are generally satisfied at a point in time and were approximately
The following tables display the Company’s disaggregated revenue by major source based on product type and timing of transfer of goods and services for the three and nine months ended September 30, 2024 and 2023:
|
|
Three months ended September 30, 2024 |
|
|||||||||
|
|
Goods transferred at a point in time |
|
|
Goods transferred over time |
|
|
Total |
|
|||
Major goods/Service line: |
|
|
|
|
|
|
|
|
|
|||
Natural gas commodity |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Natural gas environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
Electric commodity |
|
|
— |
|
|
|
|
|
|
|
||
Electric environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating segment: |
|
|
|
|
|
|
|
|
|
|||
RNG |
|
$ |
|
|
$ |
|
|
$ |
|
|||
REG |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
13
|
|
Three months ended September 30, 2023 |
|
|||||||||
|
|
Goods transferred at a point in time |
|
|
Goods transferred over time |
|
|
Total |
|
|||
Major goods/Service line: |
|
|
|
|
|
|
|
|
|
|||
Natural gas commodity |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Natural gas environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
Electric commodity |
|
|
— |
|
|
|
|
|
|
|
||
Electric environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating segment: |
|
|
|
|
|
|
|
|
|
|||
RNG |
|
$ |
|
|
$ |
|
|
$ |
|
|||
REG |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
Nine months ended September 30, 2024 |
|
|||||||||
|
|
Goods transferred at a point in time |
|
|
Goods transferred over time |
|
|
Total |
|
|||
Major goods/Service line: |
|
|
|
|
|
|
|
|
|
|||
Natural gas commodity |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Natural gas environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
Electric commodity |
|
|
— |
|
|
|
|
|
|
|
||
Electric environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating segment: |
|
|
|
|
|
|
|
|
|
|||
RNG |
|
$ |
|
|
$ |
|
|
$ |
|
|||
REG |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
|
|
Nine months ended September 30, 2023 |
|
|||||||||
|
|
Goods transferred at a point in time |
|
|
Goods transferred over time |
|
|
Total |
|
|||
Major goods/Service line: |
|
|
|
|
|
|
|
|
|
|||
Natural gas commodity |
|
$ |
|
|
$ |
|
|
$ |
|
|||
Natural gas environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
Electric commodity |
|
|
— |
|
|
|
|
|
|
|
||
Electric environmental attributes |
|
|
|
|
|
— |
|
|
|
|
||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Operating segment: |
|
|
|
|
|
|
|
|
|
|||
RNG |
|
$ |
|
|
$ |
|
|
$ |
|
|||
REG |
|
|
|
|
|
|
|
|
|
|||
|
|
$ |
|
|
$ |
|
|
$ |
|
|||
Practical expedients and remaining performance obligations
The Company recognizes the sale of natural gas and electric commodities using the right to invoice practical expedient. The Company determined that the revenues recognized as of period end correspond directly with the value transferred to customers and the Company's satisfaction of the performance obligations to date. Furthermore, with the application of the right to invoice practical expedient and in consideration that contracts related to future environmental attributes sales do not exceed one year, there were no remaining unsatisfied or partially satisfied performance obligations as of September 30, 2024 and December 31, 2023, respectively.
NOTE 5 – ACCOUNTS AND OTHER RECEIVABLES
The Company extends credit based upon an evaluation of the customer’s financial condition and, while collateral is not required, the Company periodically receives surety bonds that guarantee payment. Credit terms are consistent with industry standards and practices. Reserves for uncollectible accounts, if any, are recorded as part of general and administrative expenses in the consolidated statements of operations.
14
Accounts and other receivables consist of the following as of September 30, 2024 and December 31, 2023:
|
September 30, 2024 |
|
December 31, 2023 |
|
||
Accounts receivables |
$ |
|
$ |
|
||
Other receivables |
|
|
|
|
||
Reimbursable expenses |
|
|
|
|
||
Accounts and other receivables, net |
$ |
|
$ |
|
||
NOTE 6 – PROPERTY, PLANT AND EQUIPMENT, NET
Property, plant and equipment consists of the following as of September 30, 2024 and December 31, 2023:
|
September 30, 2024 |
|
December 31, 2023 |
|
||
Land |
$ |
|
$ |
|
||
Buildings and improvements |
|
|
|
|
||
Machinery and equipment |
|
|
|
|
||
Gas mineral rights |
|
|
|
|
||
Construction work in progress |
|
|
|
|
||
Total |
$ |
|
$ |
|
||
Less: Accumulated depreciation and amortization |
|
( |
) |
|
( |
) |
Property, plant & equipment, net |
$ |
|
$ |
|
||
Depreciation expense for property plant and equipment was $
Construction work in progress consists of RNG and REG capital expenditures on developmental projects and improvements to existing sites. Projects, on average, last between
In February 2024, the Company completed an Asset acquisition with a privately-held entity. The Company paid $
NOTE 7 – GOODWILL AND INTANGIBLE ASSETS, NET
Goodwill and intangible assets consist of the following as of September 30, 2024 and December 31, 2023:
|
|
September 30, 2024 |
|
|
December 31, 2023 |
|
||
Goodwill |
|
$ |
|
|
$ |
|
||
Intangible assets with indefinite lives: |
|
|
|
|
|
|
||
Land use rights |
|
|
|
|
|
|
||
Total intangible assets with indefinite lives: |
|
$ |
|
|
$ |
|
||
Intangible assets with finite lives: |
|
|
|
|
|
|
||
Interconnection, net of accumulated amortization |
|
$ |
|
|
$ |
|
||
Customer contracts, net of accumulated |
|
|
|
|
|
|
||
Total intangible assets with finite lives: |
|
$ |
|
|
$ |
|
||
Total Goodwill and Intangible assets |
|
$ |
|
|
$ |
|
||
15
NOTE 8 – ASSET RETIREMENT OBLIGATIONS
The Company accounts for asset retirement obligations by recording the fair value of the liability in the period in which it is incurred. The Company estimates the fair value of asset retirement obligations by calculating the estimated present value of the cost to retire the asset. Factors that are considered when determining the present value of the cost to retire the asset include future inflation and discount rates, along with estimates date(s) of retiring the asset. Additionally, changes in legal, regulatory, environmental, and political environments can affect the fair value of the obligations. As such, asset retirement obligations are considered a Level 3 financial instrument.
The $
The following table summarizes the activity associated with asset retirement obligations of the Company as of September 30, 2024 and December 31, 2023:
|
Nine months ended |
|
|
Year ended December 31, |
|
||
|
2024 |
|
|
2023 |
|
||
Asset retirement obligations—beginning of period |
$ |
|
|
$ |
|
||
Accretion expense |
|
|
|
|
|
||
Changes in estimate |
|
|
|
— |
|
||
Liabilities associated with properties sold |
|
( |
) |
|
— |
|
|
Asset retirement obligations—end of period |
$ |
|
|
$ |
|
||
NOTE 9 – DERIVATIVE INSTRUMENTS
To mitigate market risk associated with fluctuations in interest rates, the Company utilizes swap contracts under a board-approved program. The Company does not apply hedge accounting to any of its derivative instruments, and all realized and unrealized gains and losses from changes in derivative values are recognized in earnings each period.
|
|
For the three months |
|
||||
Derivative Instrument |
Location |
2024 |
|
2023 |
|
||
Interest rate swaps |
Interest expense |
$ |
( |
) |
$ |
|
|
(loss) gain |
|
$ |
( |
) |
$ |
|
|
|
|
|
|
|
|
||
|
|
For the nine months |
|
||||
Derivative Instrument |
Location |
2024 |
|
2023 |
|
||
Interest rate swaps |
Interest expense |
$ |
( |
) |
$ |
|
|
(loss) gain |
|
$ |
( |
) |
$ |
|
|
NOTE 10 – FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company’s assets and liabilities that are measured at fair value on a recurring basis include the following as of September 30, 2024 and December 31, 2023, set forth by level, within the fair value hierarchy:
|
September 30, 2024 |
|
||||||||||
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
||||
Interest rate swap derivative asset |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Asset retirement obligations |
|
|
|
|
|
( |
) |
|
( |
) |
||
Pico earn-out liability |
|
|
|
|
|
( |
) |
|
( |
) |
||
|
$ |
|
$ |
|
$ |
( |
) |
$ |
( |
) |
||
16
|
December 31, 2023 |
|
||||||||||
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Total |
|
||||
Interest rate swap derivative asset |
$ |
|
$ |
|
$ |
|
$ |
|
||||
Asset retirement obligations |
|
|
|
|
|
( |
) |
|
( |
) |
||
Pico earn-out liability |
|
|
|
|
|
( |
) |
|
( |
) |
||
|
$ |
|
$ |
|
$ |
( |
) |
$ |
( |
) |
||
The three levels of the fair value hierarchy under authoritative guidance are described as follows:
Level 1: Observable inputs that reflect unadjusted quoted market prices in active markets for identical assets or liabilities.
Level 2: Inputs are market data, other than Level 1, that are observable either directly or indirectly. Level 2 inputs include quoted market prices for similar assets or liabilities, quoted market prices for similar assets or liabilities in inactive markets and other observable information that can be corroborated by market data.
Level 3: Unobservable inputs that are not corroborated by market data, but significant to the fair value measurement.
A summary of change in the fair value of the Company’s Level 3 instrument, attributable to asset retirement obligations, for the nine months ended September 30, 2024 and the year ended December 31, 2023 is included in Note 8. The Company’s earn-out fair value liability at its Idaho agricultural digester site is determined by calculating the estimated present value of the future obligation. The present value is assessed quarterly and is based on macro-economic factors such as inflation and risk free US Treasury rates. Company specific estimates utilized include current and future interest rates, digester inlet gas flow and projected EBITDA. A weighted average probability approach is utilized for the variables discussed above. The earn-out is classified as a Level 3 financial instrument and changes in the balance are recorded in Accrued liabilities and Other liabilities within the consolidated balance sheets and in the Royalties, transportation, gathering and production fuel within the consolidated statements of operations. Interest rate swap derivatives are classified as Level 2 financial instruments and are valued utilizing quoted forward Bloomberg Short-Term Bank Yield Index Rates. In addition, certain assets are measured at fair value on a non-recurring basis when an indicator of impairment is identified and the assets’ fair values are determined to be less than its carrying value. See Note 3 for additional information.
NOTE 11 – ACCRUED LIABILITIES
The Company’s accrued liabilities consists of the following as of September 30, 2024 and December 31, 2023:
|
September 30, 2024 |
|
December 31, 2023 |
|
||
Accrued expenses |
$ |
|
$ |
|
||
Payroll and related benefits |
|
|
|
|
||
Royalty |
|
|
|
|
||
Utility |
|
|
|
|
||
Accrued interest |
|
|
|
|
||
Other |
|
|
|
|
||
Accrued liabilities |
$ |
|
$ |
|
||
NOTE 12 – DEBT
The Company’s debt consists of the following as of September 30, 2024 and December 31, 2023:
|
September 30, 2024 |
|
December 31, 2023 |
|
||
Term loans |
$ |
|
$ |
|
||
Less: current principal maturities |
|
( |
) |
|
( |
) |
Less: debt issuance costs (on long-term debt) |
|
( |
) |
|
( |
) |
Long-term debt |
$ |
|
$ |
|
||
Current portion of long-term debt |
|
|
|
|
||
Total debt |
$ |
|
$ |
|
||
Amended Credit Agreement
On December 12, 2018, Montauk Energy Holdings LLC (“MEH”), a wholly owned subsidiary of the Company, entered into the Second Amended and Restated Revolving Credit and Term Loan Agreement (as amended, “Credit Agreement”), by and among MEH, the financial institutions from time to time party thereto as lenders and Comerica Bank, as the administrative agent, sole lead arranger
17
and sole bookrunner (“Comerica”). The Credit Agreement (i) amended and restated in its entirety MEH’s prior revolving credit and term loan facility, dated as of August 4, 2017, as amended, with Comerica and certain other financial institutions and (ii) replaced in its entirety the prior credit agreement, dated as of August 4, 2017, as amended, between Comerica and Bowerman Power LFG, LLC, a wholly-owned subsidiary of MEH.
On March 21, 2019, MEH entered into the first amendment to the Credit Agreement (the “First Amendment”), which clarified a variety of terms, definitions and calculations in the Credit Agreement. The Credit Agreement requires the Company to maintain customary affirmative and negative covenants, including certain financial covenants, which are measured at the end of each fiscal quarter. On September 12, 2019, the Company entered into the second amendment to the Credit Agreement (the "Second Amendment"). Among other matters, the Second Amendment redefined the Fixed Charge Coverage Ratio (as defined in the Credit Agreement), reduced the commitments under the revolving credit facility to $
On January 4, 2021, the Company, Montauk Holdings Limited (“MNK”) and Montauk Holdings USA, LLC (a direct wholly-owned subsidiary of MNK at the time, “Montauk USA”) entered into a series of transactions, including an equity exchange and a distribution collectively referred to as the “Reorganization Transactions,” that resulted in the Company owning all of the assets and entities (other than Montauk USA) previously owned by Montauk USA, and Montauk Renewables became a direct wholly-owned subsidiary of MNK. In connection with the completion of the Reorganization Transactions and the IPO, the Company entered into the third amendment to the Credit Agreement (the “Third Amendment”). This amendment permitted the change of control provisions, as defined in the underlying agreement, to permit the Reorganization Transactions and the IPO to be completed.
On December 21, 2021, MEH entered into the fourth amendment to the Second Amended and Restated Revolving Credit and Term Loan Agreement ("the Fourth Amendment"). The current credit agreement, which is secured by a lien on substantially all assets of the Company and certain of its subsidiaries, provides for a $
The Company accounted for the Fourth Amendment as both a debt modification and debt extinguishment in accordance with ASC 470, Debt (“ASC 470”). In connection with the Credit Agreement, the Company paid $
As of September 30, 2024, $
As of September 30, 2024, the Company was in compliance with all applicable financial covenants under the Credit Agreement.
NOTE 13 – INCOME TAXES
The Company’s provision for income taxes in interim periods is typically computed by applying the estimated annual effective tax rates to income or loss before income taxes for the period. In addition, non-recurring or discrete items are recorded during the period in which they occur. For the nine months ended September 30, 2024, the Company utilized an estimated effective tax rate.
|
|
For the three months |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Expense provision for income taxes |
|
$ |
|
|
$ |
|
||
Effective tax rate |
|
|
% |
|
|
% |
||
|
|
For the nine months |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Expense provision for income taxes |
|
$ |
|
|
$ |
|
||
Effective tax rate |
|
|
% |
|
|
% |
||
18
The effective tax rate of
The effective tax rate of
Income tax expense for the three and nine months ended September 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of
NOTE 14 – SHARE-BASED COMPENSATION
The board of directors of Montauk Renewables adopted the Montauk Renewables, Inc. Equity and Incentive Compensation Plan (“MRI EICP”) in January 2021. Following the closing of the IPO, the board of directors of Montauk Renewables approved the grant of non-qualified stock options, restricted stock units and restricted share awards to the employees of Montauk Renewables and its subsidiaries in January 2021. In connection with the restricted share awards, the officers of the Company made elections under Section 83(b) of the Code. Pursuant to such elections, the Company withheld
In connection with a May 2021 asset acquisition,
In 2023, the board of directors of the Company approved the grant of non-qualified stock options to the executive officers of the Company, which vest ratably over a period of three to five years. Stock compensation expense related to these awards was $
The restricted shares, restricted stock units and option awards are subject to vesting schedules and are subject to the terms and conditions of the MRI EICP and related award agreements including, in the case of the restricted share awards, each officer having made an election under Section 83(b) of the Code.
Options granted under the MRI EICP allow the recipient to receive the Company’s common stock equal to the appreciation in the fair market value of the Company’s common stock between the grant date and the exercise and settlement of options into shares as of the exercise dates. The fair value of the MRI EICP options was estimated using the Black-Scholes option pricing model. Three
19
blocks of options have been awarded since inception of the plan with the following weighted-average assumptions (no dividends were expected):
|
|
September 2023 Awards |
|
|
Options awarded |
|
|
|
|
Risk-free interest rate |
|
|
||
Expected volatility |
|
|
||
Expected option life (in years) |
|
|
||
Grant-date fair value |
|
$ |
|
|
|
|
|
|
|
|
|
April 2023 Awards |
|
|
Options awarded |
|
|
|
|
Risk-free interest rate |
|
|
||
Expected volatility |
|
|
||
Expected option life (in years) |
|
|
||
Grant-date fair value |
|
$ |
|
|
|
|
|
|
|
|
|
January 2021 Awards |
|
|
Options awarded |
|
|
|
|
Risk-free interest rate |
|
|
% |
|
Expected volatility |
|
|
% |
|
Expected option life (in years) |
|
|
|
|
Grant-date fair value |
|
$ |
|
|
The following table summarizes the restricted shares, restricted stock units and options outstanding under the MRI EICP as of September 30, 2024 and September 30, 2023, respectively:
|
|
Restricted Shares |
|
|
Restricted Stock Units |
|
|
Options |
|
|||||||||||||||
|
|
Number of |
|
|
Weighted |
|
|
Number of |
|
|
Weighted |
|
|
Number of |
|
|
Weighted |
|
||||||
End of period - December 31, 2023 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Beginning of period - January 1, 2024 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Vested |
|
|
( |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Forfeited |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
End of period - Balance at September 30, 2024 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
End of period - December 31, 2022 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Beginning of period - January 1, 2023 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
Granted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
Vested |
|
|
( |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Forfeited |
|
|
( |
) |
|
|
|
|
|
( |
) |
|
|
|
|
|
|
|
|
|
||||
End of period - September 30, 2023 |
|
|
|
|
$ |
|
|
|
|
|
$ |
|
|
|
|
|
$ |
|
||||||
As of September 30, 2024 no vested options have been exercised. Unrecognized MRI EICP compensation expense for awards the Company expects to vest as of September 30, 2024, was $
NOTE 15 – DEFINED CONTRIBUTION PLAN
20
NOTE 16 – RELATED PARTY TRANSACTIONS
Intercompany Transactions
On January 26, 2021, the Company entered into a Loan Agreement and Secured Promissory Note (the “Initial Promissory Note”) with Montauk Holdings Limited (“MNK”). MNK is currently an affiliate of the Company and certain of the Company’s directors are also directors and executive officers of MNK. Pursuant to the Initial Promissory Note, the Company advanced a cash loan of $
Under applicable guidance for variable interest entities in ASC 810, Consolidation, the Company determined that MNK is a variable interest entity. The Company concluded that it is not the primary beneficiary of the variable interest entity, as the Company does not have a controlling financial interest and does not have the power to direct the activities that most significantly impact the economic performance of MNK. Accordingly, the Company concluded that presentation of the Amended Promissory Note as a related party receivable remains appropriate. The maximum exposure to loss is limited to the Promissory Note principal and accrued interest, which totaled $
MNK was delisted from the JSE on January 26, 2021. The MNK Board of Directors and Shareholders held its annual general meeting in March 2023 and voted to take MNK private.
Employment Transactions
The Company signed a long-term immaterial lease in December 2023 with a landowner in North Carolina. This lease enabled the Company to construct a feedstock collection system on the property which is owned by the Company. In September 2024, the Company hired the landowner as an employee to assist in the procuring of additional long-term leases on farms for additional collection system installations related to feedstock in North Carolina.
Related Party Reimbursements
Periodically the Company will reimburse MNK and HCI Managerial Services Proprietary Limited, the administrator for the Company’s secondarily listed Johannesburg Stock Exchange trading symbol, for expenses incurred on behalf of the Company. Amounts reimbursed were $
NOTE 17 – SEGMENT INFORMATION
The Company’s operating segments for the three and nine months ended September 30, 2024 and 2023 are Renewable Natural Gas and Renewable Electricity Generation. Renewable Natural Gas includes the production of RNG. Renewable Electricity Generation includes generation of electricity at biogas-to-electricity plants. The Corporate segment is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation of the Company’s condensed consolidated financial statements.
21
performance of each segment and allocates the Company’s resources. In the following tables, “RNG” refers to Renewable Natural Gas and “REG” refer to Renewable Electricity Generation.
|
|
Three months ended September 30, 2024 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Total revenue |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Net income (loss) |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
|
|
||
EBITDA |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Adjusted EBITDA (1) |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
||||
The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the three months ended September 30, 2024:
|
|
Three months ended September 30, 2024 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Net income (loss) |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
|
||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest expense |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|||
Income tax expense |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Impairment loss |
|
|
|
|
|
|
|
|
— |
|
|
|
|
|||
Net loss on sale of assets |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Adjusted EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
|
|
Three months ended September 30, 2023 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Total revenue |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Net income (loss) |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
EBITDA |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Adjusted EBITDA (2) |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
||||
(2)
The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the three months ended September 30, 2023:
|
|
Three months ended September 30, 2023 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Net income (loss) |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest expense |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Income tax expense |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Impairment loss |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Adjusted EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
22
For the three months ended September 30, 2024 and 2023, two and four customers, respectively, made up greater than 10% of total revenues.
|
|
Three months ended September 30, 2024 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Customer A |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer B |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
|
|
Three months ended September 30, 2023 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Customer A |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer B |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer C |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer D |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
|
|
Nine months ended September 30, 2024 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Total revenue |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Net income (loss) |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
|
|
||
EBITDA |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Adjusted EBITDA (3) |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
||||
(3)
The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the nine months ended September 30, 2024:
|
|
Nine months ended September 30, 2024 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Net income (loss) |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
|
||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest expense |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|||
Income tax expense |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Impairment loss |
|
|
|
|
|
|
|
|
— |
|
|
|
|
|||
Net loss on sale of assets |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Transaction costs |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Adjusted EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
|
|
Nine months ended September 30, 2023 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Total revenue |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
||||
Net income (loss) |
|
|
|
|
|
( |
) |
|
|
( |
) |
|
|
|
||
EBITDA |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Adjusted EBITDA (4) |
|
|
|
|
|
|
|
|
( |
) |
|
|
|
|||
Total assets |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Capital expenditures |
|
|
|
|
|
|
|
|
|
|
|
|
||||
(4)
23
The following table is a reconciliation of the Company’s reportable segments’ net income (loss) from continuing operations to Adjusted EBITDA for the nine months ended September 30, 2023:
|
|
Nine months ended September 30, 2023 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Net income (loss) |
|
$ |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
|
||
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest expense |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Income tax benefit |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
Impairment loss |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Net loss on sale of assets |
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Transaction costs |
|
|
— |
|
|
|
— |
|
|
|
|
|
|
|
||
Adjusted EBITDA |
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
$ |
|
|||
For both the nine months ended September 30, 2024 and 2023, four customers made up greater than 10% of total revenues.
|
|
Nine months ended September 30, 2024 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Customer A |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer B |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer C |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer D |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
|
|
Nine months ended September 30, 2023 |
|
|||||||||||||
|
|
RNG |
|
|
REG |
|
|
Corporate |
|
|
Total |
|
||||
Customer A |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer B |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer C |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
Customer D |
|
|
% |
|
|
— |
|
|
|
— |
|
|
|
% |
||
NOTE 18 – LEASES
The Company leases office space and other office equipment under operating lease arrangements (with initial terms greater than twelve months), expiring in various years through 2033. These leases have been entered into to better enable the Company to conduct business operations. Office space is leased to provide adequate workspace for employees in Pittsburgh, Pennsylvania and Houston, Texas. Office space and office equipment agreements that exceed 12 months are accounted for as operating leases in accordance with ASC 842, Leases.
The Company also leases safety equipment for the various operational sites in the United States. The term of certain equipment exceeds twelve months and is accordingly classified as a finance lease under ASC 842. These finance leases expire in 2026 and were entered into in order to provide a safe work environment for operational employees.
The Company determines if an arrangement is, or contains, a lease at inception based on whether that contract conveys the right to control the use of an identified asset in exchange for consideration for a period of time. For all operating and finance lease arrangements, the Company presents at the commencement date: a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term.
The Company has elected, as a practical expedient, not to separate non-lease components from lease components, and instead account for each separate component as a single lease component for all lease arrangements, as lessee. In addition, the Company has elected, as a practical expedient, not to apply lease recognition requirements to leases with a term of one year or less. In determination of the lease term, the Company considers the likelihood of lease renewal options and lease termination provisions.
The Company uses its incremental borrowing rate, as the basis to calculate the present value of future lease payments at lease commencement. The incremental borrowing rate represents the rate that would approximate the rate to borrow funds on a collateralized basis over a similar term and in a similar economic environment.
24
Supplemental information related to operating lease arrangements was as follows:
|
|
For the three months ended September 30, |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Cash paid for amounts included in the measurement of |
|
$ |
|
|
$ |
|
||
Weighted average remaining lease term (in years) |
|
|
|
|
|
|
||
Weighted average discount rate |
|
|
% |
|
|
% |
||
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
|
For the nine months ended September 30, |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Cash paid for amounts included in the measurement of |
|
$ |
|
|
$ |
|
||
Weighted average remaining lease term (in years) |
|
|
|
|
|
|
||
Weighted average discount rate |
|
|
% |
|
|
% |
||
Future minimum operating lease payments are as follows:
Year Ending |
|
|
|
|
2024 |
|
$ |
|
|
2025 |
|
|
|
|
2026 |
|
|
|
|
2027 |
|
|
|
|
2028 |
|
|
|
|
Thereafter |
|
|
|
|
Imputed interest |
|
|
( |
) |
Total |
|
$ |
|
|
Supplemental information related to finance lease arrangements was as follows:
|
|
For the three months ended September 30, |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Cash paid for amounts included in the measurement of |
|
$ |
|
|
$ |
|
||
Weighted average remaining lease term (in years) |
|
|
|
|
|
|
||
Weighted average discount rate |
|
|
% |
|
|
% |
||
|
|
|
|
|
|
|
||
|
|
|
|
|||||
|
|
For the nine months ended September 30, |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Cash paid for amounts included in the measurement of |
|
$ |
|
|
$ |
|
||
Weighted average remaining lease term (in years) |
|
|
|
|
|
|
||
Weighted average discount rate |
|
|
% |
|
|
% |
||
Future minimum finance lease payments are as follows:
Year Ending |
|
|
|
|
2024 |
|
$ |
|
|
2025 |
|
|
|
|
2026 |
|
|
|
|
2027 |
|
|
|
|
2028 |
|
|
|
|
Thereafter |
|
|
|
|
Imputed interest |
|
|
( |
) |
Total |
|
$ |
|
|
25
NOTE 19 – INCOME PER SHARE
Basic and diluted income per share was computed using the following common share data for the three and nine months ended September 30, 2024 and 2023, respectively:
|
|
For the three months ended September 30, |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Net income |
|
$ |
|
|
$ |
|
||
Basic weighted-average shares outstanding |
|
|
|
|
|
|
||
Dilutive effect of share-based awards |
|
|
|
|
|
|
||
Diluted weighted-average shares outstanding |
|
|
|
|
|
|
||
Basic income per share |
|
$ |
|
|
$ |
|
||
Diluted income per share |
|
$ |
|
|
$ |
|
||
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
||
|
|
For the nine months ended September 30, |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Net income |
|
$ |
|
|
$ |
|
||
Basic weighted-average shares outstanding |
|
|
|
|
|
|
||
Dilutive effect of share-based awards |
|
|
|
|
|
|
||
Diluted weighted-average shares outstanding |
|
|
|
|
|
|
||
Basic income per share |
|
$ |
|
|
$ |
|
||
Diluted income per share |
|
$ |
|
|
$ |
|
||
NOTE 20 – COMMITMENTS AND CONTINGENCIES
Environmental
The Company is subject to a variety of environmental laws and regulations governing discharges to the air and water, as well as the handling, storage and disposing of hazardous or waste materials. The Company believes its operations currently comply in all material respects with all environmental laws and regulations applicable to its business. However, there can be no assurance that environmental requirements will not change in the future or that the Company will not incur significant costs to comply with such requirements.
Contingencies
The Company, from time to time, may be involved in litigation. At September 30, 2024, management does not believe there are any matters outstanding that would have a material adverse effect on the Company’s financial position or results of operations.
NOTE 21 – SUBSEQUENT EVENTS
The Company evaluated its September 30, 2024 condensed consolidated financial statements through the date the financial statements were issued. The Company is not aware of any subsequent events which would require recognition or disclosure in the consolidated financial statements, except for the matter described below.
On October 22, 2024, the Company entered into an asset purchase agreement to sell one of its renewable natural gas sites for a purchase price of $
26
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and the related notes to those statements included elsewhere in this Quarterly Report on Form 10-Q. Throughout this section, dollar amounts and production volumes are expressed in thousands, except for per share amounts, MMBtu, MWh, and RIN pricing amounts and unless otherwise indicated.
In addition to historical financial information, the following discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of many factors, including those discussed under “Cautionary Note Regarding Forward-Looking Statements,” “Item 1A.–Risk Factors” of our 2023 Annual Report, and elsewhere in this report.
Overview
Montauk Renewables is a renewable energy company specializing in the recovery and processing of biogas from landfills and other non-fossil fuel sources for beneficial use as a replacement to fossil fuels. We develop, own, and operate RNG projects, using proven technologies that supply RNG into the transportation industry and use RNG to produce Renewable Electricity. We are one of the largest U.S. producers of RNG, having participated in the industry for over 30 years. We established our operating portfolio of 12 RNG and two Renewable Electricity projects through self-development, partnerships, and acquisitions that span eight states.
Biogas is produced by microbes as they break down organic matter in the absence of oxygen (during a process called anaerobic digestion). Our two current sources of commercial scale biogas are LFG or ADG. We typically secure our biogas feedstock through long-term fuel supply agreements and property lease agreements with biogas site hosts. Once we secure long-term fuel supply rights, we design, build, own, and operate facilities that convert the biogas into RNG or use the processed biogas to produce Renewable Electricity. We sell the RNG and Renewable Electricity through a variety of term length agreements. Because we are capturing waste methane and making use of a renewable source of energy, our RNG and Renewable Electricity generate valuable Environmental Attributes, which we are able to monetize under federal and state renewable initiatives.
Our current operating projects produce either RNG or Renewable Electricity by processing biogas from landfill sites or agricultural waste from livestock farms. We view agricultural waste from livestock farms as a significant opportunity for us to expand our RNG business, and we continue to evaluate other agricultural feedstock opportunities. We believe that our business model and technology are highly scalable given availability of biogas from agriculturally derived sources, which will allow us to continue to grow through prudent development and complimentary acquisitions.
Recent Developments
RINs Generated but Unsold
Our profitability is highly dependent on the market price of Environmental Attributes, including the market price for RINs. As we self-market a significant portion of our RINs, a decision not to commit to transfer available RINs during a period will impact our revenue and operating profit. The following table summarizes select historical data related to RINs generated, RINs sold, and RINs generated but unsold. As we self-market a significant portion of our RINs and as the RFS is based on annual compliance, any strategic decision to not monetize available RINs in a quarter could impact the timing of operating revenues recognized during a fiscal year. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments. The timing of RIN transfers can vary year over year and by period within a year and is contingent on various factors including, but not limited to: (a) the Company’s expectations on RIN index price, (b) operational needs of the Company, (c) obligated parties purchase needs, or (d) the type of customer among other matters.
Calendar Quarter |
RINs Available for Sale |
RINs Sold |
RINs sold as % of RINs Available |
RINs Available but Unsold |
RINs Unsold as % of RINs Available |
2023 First Quarter |
11,215 |
2,949 |
26.3% |
8,266 |
73.7% |
2023 Second Quarter |
20,407 |
17,441 |
85.5% |
2,966 |
14.5% |
2023 Third Quarter |
14,514 |
13,750 |
94.7% |
764 |
5.3% |
2023 Fourth Quarter |
10,904 |
10,796 |
99.0% |
108 |
1.0% |
2024 First Quarter |
11,240 |
7,889 |
70.2% |
3,351 |
29.8% |
2024 Second Quarter |
14,707 |
10,000 |
68.0% |
4,707 |
32.0% |
2024 Third Quarter |
15,895 |
15,750 |
99.1% |
145 |
0.9% |
27
Capital Development Summary
The following summarizes our ongoing development growth plans expected capacity contribution, anticipated commencement of operations, and capital expenditure estimate, respectively excluding the Montauk Ag Renewables Development Project:
Development Opportunity |
Estimated Capacity Contribution (MMBtu/day) |
Anticipated Commencement Date |
Estimated Capital Expenditure |
Second Apex RNG Facility |
2,100 |
2025 second quarter |
$30,000-$40,000 |
Blue Granite RNG Facility |
900 |
2027 |
$25,000-$35,000 |
Bowerman RNG Facility |
3,600 |
2027 |
$85,000-$95,000 |
European Energy Facilities |
N/A |
2027 |
$65,000-$75,000 |
Second Apex RNG Facility
In 2022, we announced the planned construction of a second RNG processing facility at the Apex landfill. The construction of a second facility under our existing fuel supply agreement was triggered by biogas feedstock volumes exceeding production capabilities and discussions with the landfill host waste intake forecasted projections. As the landfill host continues to increase waste intake, we believe that the additional 2,100 MMBtu per day of production capacity will allow us to process the currently forecasted increase in biogas feedstock volumes. While the landfill host continues to increase waste intake, we continue to expect there could be a period where we have excess available capacity after the second facility is commissioned. We continue to incur capital expenditures for this project and continue to expect commercial operations in the second quarter of 2025.
Blue Granite RNG Project
In 2023, we announced the planned entrance into South Carolina with the development of a new landfill gas-to-RNG facility. The planned project is expected to contribute approximately 900 MMBtu per day of production capacity upon commissioning. We continue to experience delays with our interconnection, most recently due to the utility informing us of their near-term prioritization of remediation efforts from the impacts of Hurricane Helene. We continue to review various alternatives related to interconnection opportunities as part of our considerations for offtake options with the understanding those alternatives may differ from initial development project assumptions. We expect the utility interconnection initially included in our development assumptions to accept the production from this facility but will require other upgrades for their system to accommodate our interconnection. The prioritization of recovery from Hurricane Helene will delay these utility upgrades and directly impact our interconnection schedule delaying our commissioning expectation of this facility into 2027. Our pace of capital deployment for this project has slowed due to the delay of the utility and we do not expect to incur significant capital expenditures on this project through the remainder of 2024. We expect to resume capital expenditures for this project mid 2025.
Bowerman RNG Project
In 2023, we announced a planned development of a renewable natural gas landfill project in Irvine, CA at the Frank R. Bowerman Landfill. The project is anticipated to process the large and growing volumes of biogas in excess of the existing capacity of the REG facility. We currently expect facility commissioning in 2027 and continue to expect the capital investment to range between $85,000 and $95,000. As part of the agreement to develop the RNG plant, we also agreed to work with the landfill host on the landfill's management of its wellfield and its flare facility permit requirements. The landfill has proposed corresponding changes to our agreement which could have impacts to our existing, agreed upon commissioning schedule. We continue to work with the landfill on these proposed changes to assess what, if any, impact these changes could additionally have related to receipt of required regional regulatory construction permits. The project is anticipated to have production nameplate capacity of approximately 3,600 MMBtu per day, assuming currently forecasted biogas feedstock volumes that are projected to be available from the host landfill at the time of commissioning. We continue to incur capital expenditures for this project.
Carbon Dioxide Beneficial Use Opportunity
In February 2024, we signed a contract for the delivery of 140 thousand tons per year of biogenic carbon dioxide (“CO2”) from our Texas facilities. We intend to capture, clean and liquefy CO2 at select Texas facilities, at which point it will be transported to EE North America's (“EENA”), Houston Texas-based e-methanol facility. The delivery term is expected to last at least 15 years and we continue to expect delivery to begin in 2027. During the second quarter of 2024, we completed initial site surveys related to locating the CO2 processing equipment. We have also received equipment proposals from multiple vendors all having prior experience with
28
liquid CO2 capture and processing. We continue to anticipate commissioning in 2027 and we expect the capital investment to range between $65,000 and $75,000 with capital expenditure beginning in 2025 for long lead equipment and design engineering.
Montauk Ag Renewables Acquisition
In 2021, through a wholly-owned subsidiary Montauk Ag Renewables, we completed an asset purchase related to developing technology to recover residual natural resources from the waste streams of modern agriculture and to refine and recycle such waste products through proprietary and other processes in order to produce high quality renewable natural gas to generate renewable electricity, to generate North Carolina swine RECs, and to produce micronutrient organic fertilizer alternatives (the “Montauk Ag Renewables Acquisition”).
In connection with the July 2023 REC agreement with Duke Energy (“Duke”), our Board of Directors approved funding for the first phase of the North Carolina development project in September 2023. Once construction has been completed on the first phase and the facility has been fully commissioned, the project will provide sufficient capacity to satisfy the Duke REC agreement through the deployment of up to seven operational processing lines at the Turkey Creek facility. Including the original equipment acquired in the Montauk Ag Renewables Acquisition, the Turkey, NC asset acquisition, and the relocation of the Magnolia, NC site reactor to Turkey, NC, we currently expect the first phase capital investment to range between $140,000 and $160,000.
We continue to engage with regulatory agencies in North Carolina to confirm the means and methods of power generation from swine waste which will be eligible for Renewable Energy Credits under North Carolina’s Renewable Energy Portfolio Standards in anticipation of commercial production. In early 2024, we received notification from the North Carolina Utilities Commission that the Turkey, NC location was approved for a New Renewables Energy Facility ("NREF") designation and Certificate of Public Convenience and Necessity (“CPCN”). In the first quarter of 2024, we submitted an amendment to our NREF application, deemed complete by the public staff of the North Carolina Utilities Commission ("NCUC"). In August 2024, we received notice from the NCUC that our NREF amendment application was approved. In October 2024, we received notice from the NCUC that our application for a CPCN and registration for a NREF related to the sale of electricity to generate swine RECs was approved for public notice. We continue to work with the utility providers regarding the utility infrastructure design for the electricity interconnection. Survey and pre-construction activities for the electricity interconnection remain ongoing and in line with our commissioning schedule.
We signed a receipt interconnection agreement with Piedmont Natural Gas for the Turkey, NC location. This agreement is structured to coincide with the development timeline at the Turkey, NC location. Piedmont Natural Gas has submitted the design of the gas interconnection for regulatory approval and we expect the interconnection construction to begin in 2024 and be completed in line with our commissioning timeline. This gas interconnection is a necessary for the project to begin the registration process to obtain regulatory approvals under either the federal RFS or state LCFS programs. Completing this process will enable the Turkey, NC location to have ability to use the RNG to produce electricity or to inject into the natural gas supply.
We continue to use the pilot reactor that was relocated and previously operated prior to the 2021 Montauk Ag Renewables Acquisition. In connection with the hog space cycle times with our feedstock supply partners, the pilot reactor testing includes refining feedstock conveyance, equipment processing, product gas composition, and the composition of the solid output. We have processed tested both the biogas and micronutrient organic fertilizer alternatives. We are also continuing to staff the Turkey, NC location. We continue to plan for a rolling commissioning schedule for the remaining processing lines through the second half of 2025. We expect to begin generating revenues in 2025 and have sufficient capacity to satisfy the Duke REC agreement after final commissioning during the second half of 2025.
The feedstock supply agreements we have signed allowed us to continue to refine our expected feedstock collection process. This process involves installing equipment on the farms under agreements, collecting feedstock and processing the waste through multiple phases of solids concentration at both the farm and our Turkey, NC location. We have completed the majority of the installation of collection process equipment on two farms for which we have feedstock agreements but continue to refine our collection methods. During the fourth quarter of 2024, we continue to bring additional farms under contract to secure additional feedstock supply.
We continue to develop the opportunities with Montauk Ag Renewables and can give no assurances that our plans related to this acquisition will meet our expectations. Utility interconnection, both inbound to and outbound from our centralized Turkey, NC processing facility is dependent on factors outside of our control. Our current construction timeline and costs are subject to delays or costs increases, respectively. We continue to design and plan for the development of the Turkey, NC facility to be used for commercial production. We expect the Magnolia, NC location to be used for various feedstock processing needs. Based on our current development timeline expectations, we do not expect to commence significant revenue generating activities until 2025. We intend to contract with additional farms to secure feedstock sources for future production processes.
29
Waste-stream Biogas Recovery
In October 2024, a collaboration with Emvolon was announced to transform methane emissions from waste stream biogas into high-value carbon negative fuel. Leveraging Emvolon's patented technology, the initial pilot is a small-scale demonstration of recovering and converting biogas into green methanol. We expect the pilot to take place at our Atascocita facility in Houston, Texas. The pilot is designed to provide proof of concept to eventually move to a commercial facility capable of producing up to 15 thousand gallons of green methanol per year and may eventually lead to a full-scale, commercial system capable of producing up to 2,400 gallons of methanol annually at the same or similar sites. We do not expect short term financial benefits from this demonstration nor a disruption to our operations.
Key Trends
Market Trends Affecting the Renewable Fuel Market
We believe rising demand for RNG is attributable to a variety of factors, including growing public support for renewable energy, U.S. governmental actions to increase energy independence, environmental concerns increasing demand for natural gas powered vehicles, job creation, and increasing investment in the renewable energy sector.
Key drivers for the long-term growth of RNG include the following factors:
Factors Affecting Our Future Operating Results:
Conversion of Electricity Projects to RNG Projects:
We continue to evaluate opportunities to convert our remaining facilities from Renewable Electricity to RNG production. These opportunities tend to be most attractive for any merchant electricity facilities given the favorable economics for the combined sale of RNG and RINs relative to the combined sale of market rate electricity and RECs. This strategy has been an increasingly attractive avenue for growth since 2014 when RNG from landfills became eligible for D3 RINs. However, during the conversion of a project, there is a gap in production while the electricity project is offline until it commences operation as an RNG facility, which can adversely affect us. This timing effect may adversely affect our operating results as a result of our potential conversion of Renewable Electricity projects. Upon completion of a conversion, we expect that the increase in revenue upon commencement of RNG production will more than offset the loss of revenue from Renewable Electricity production. Historically, we have taken advantage of these opportunities on a gradual basis at our merchant electricity facilities, such as Atascocita and Coastal Plains.
Acquisition and Development Pipeline
The timing and extent of our development pipeline affects our operating results due to:
30
Regulatory, Environmental and Social Trends
Regulatory, environmental and social factors are key drivers that incentivize the development of RNG and Renewable Electricity projects and influence the economics of these projects. We are subject to the possibility of legislative and regulatory changes to certain incentives, such as RINs, RECs and GHG initiatives. On July 12, 2023, the EPA issued final rules in the Federal Register for the RFS volume requirements for 2023-2025. Final volumes for cellulosic biofuel were set at 838, 1,090 and 1,376 million D3 RINs for the three years 2023, 2024 and 2025, respectively. While new RNG projects in the US in 2024 have grown at a rate of approximately 20% over 2023, there is still a shortage of cellulosic biofuel (D3 RINs) compared to the volumes set for 2024 and 2025. While the EPA denied all small refinery exemptions in 2022, a federal appeals court rejected EPA’s denial of these small refinery exemptions in July 2024. This appeal, along with the shortfall of cellulosic biofuels (D3 RINs) are expected to impact a future EPA action possibly in 2025 to balance the market. The final rule also included significant changes to the existing RFS program, referred to as biogas regulatory reform, that will require the RNG industry to modify how all RINs are generated. New RFS participating facilities that register July 1, 2024, or after will have to meet the biogas regulatory reform provisions beginning July 1, 2024. Existing RFS participating facilities which registered prior to July 1, 2024, will have until January 1, 2025, to come into compliance with biogas regulatory reforms. For existing registrants, registration updates must be submitted by October 1, 2024. On January 1, 2025, all RFS participants must comply with biogas regulatory reform provisions. The EPA finalized a limitation that biogas from one facility has a single use under the RFS as proposed (i.e., biointermediate, RNG or CNG/LNG via biogas closed distribution system). The EPA clarified that this does not preclude non-RFS uses at same facility.
The EPA has indicated it will not meet the statutorily required deadline of November 2024 to finalize 2026 obligations under the RFS. The EPA expects to target March 2025 to propose RFS obligations for 2026.
In December 2023, CARB released the formal proposal for new LCFS rules. CARB held a public workshop for the proposed rules on April 10, 2024. In early October 2024, CARB released another set of 15-day amendments with the most notable near-term change of increasing CI reduction stringency from 5% to 9% in 2025 along with a 20% to 30% reduction by 2030. The proposed rule also creates a 2045 target of 90% reduction. This reduction would have the potential impact of reducing the number of net credits in the program. A public hearing for the proposed rule is set for November 8, 2024. Final rules are expected to be submitted to CARB’s board for approval sometime in the first quarter of 2025. The industry may see pricing volatility including potential increase to LCFS credit prices. However, price increases are not anticipated until after 2025. Also in the proposed rules is a phase-out of avoided methane crediting for dairy and swine manure pathways by 2040 for CNG usage and through 2045 for RNG used to produce hydrogen. RNG projects with avoided methane that were certified before the effective date of the new regulation will be allowed three consecutive 10-year crediting periods. Avoided methane RNG projects that break ground on or after the effective date of the regulation and before January 1, 2030, will be allowed up to two consecutive 10-year crediting periods. If the executive officer of CARB approves a gas map by July 1, 2026, then physical flow of gas to California must be demonstrated by December 31, 2037. If no gas map is approved, the proposed rules will allow reporting entities until January 1, 2041 to demonstrate gas flow.
The LCFS program require annual verification of the CI score assigned to a project. Annual verification could significantly affect the profitability of a project, particularly in the case of a livestock farm project.
Factors Affecting Revenue
Our total operating revenues include renewable energy and related sales of Environmental Attributes. Renewable energy sales primarily consist of the sale of biogas, including LFG and ADG, which is either sold or converted to Renewable Electricity. Environmental Attributes are generated and monetized from the renewable energy.
We report revenues from two operating segments: Renewable Natural Gas and Renewable Electricity Generation. Corporate relates to additional discrete financial information for the corporate function; primarily used as a shared service center for maintaining functions such as executive, accounting, treasury, legal, human resources, tax, environmental, engineering, and other operations functions not otherwise allocated to a segment. As such, the Corporate segment is not determined to be an operating segment but is discretely disclosed for purposes of reconciliation to the Company’s consolidated financial statements.
31
Our operating revenues are priced based on published index prices which can be influenced by factors outside our control, such as market impacts on commodity pricing and regulatory developments. With our royalty payments structured as a percentage of revenue, royalty payments fluctuate with changes in revenues. Due to these factors, we place a primary focus on managing production volumes and operating and maintenance expenses as these factors are more controllable by us.
RNG Production
Our RNG production levels are subject to fluctuations based on numerous factors, including:
Disruptions to Production: Disruptions to waste placement operations at our active landfill sites, severe weather events, or failure or degradation of our or a landfill operator’s equipment or interconnection or transmission problems could result in a reduction of our RNG production. We strive to proactively address any issues that may arise through preventative maintenance, process improvement and flexible redeployment of equipment to maximize production and useful life.
32
Pricing
Our Renewable Natural Gas and Renewable Electricity Generation segments’ revenues are primarily driven by the prices under our off-take agreements and PPAs and the amount of RNG and Renewable Electricity that we produce. We sell the RNG produced from our projects under a variety of termed agreements to counterparties, with contract terms varying from three years to five years. Our contracts with counterparties are typically structured to be based on varying natural gas price indices for the RNG produced. All of the Renewable Electricity produced at our biogas-to-electricity projects is sold under long-term contracts to creditworthy counterparties, typically under a fixed price arrangement with escalators.
The pricing of Environmental Attributes, which accounts for a substantial portion of our revenues, is subject to volatility based on a variety of factors, including regulatory and administrative actions and commodity pricing.
The sale of RINs, which is subject to market price fluctuations, accounts for a substantial portion of our revenues. We manage against the risk of these fluctuations through forward sales of RINs, with heavy emphasis on direct sales to obligated parties. Realized prices for Environmental Attributes monetized in a year may not correspond directly to index prices due to the forward selling of commitments.
Factors Affecting Operating Expenses
Our operating expenses include royalties, transportation, gathering and production fuel expenses, project operating and maintenance expenses, general and administrative expenses, depreciation and amortization, net loss (gain) on sale of assets, impairment loss and transaction costs. Our operating expenses can be subject to inflationary cost increases that are largely out of our control.
33
Key Operating Metrics
Total operating revenues reflect both sales of renewable energy and sales of related Environmental Attributes. As a result, our revenues are primarily affected by unit production of RNG and Renewable Electricity, production of Environmental Attributes, and the prices at which we monetize such production. Set forth below is an overview of these key metrics:
34
Comparison of Three Months Ended September 30, 2024 and 2023
The following table summarizes the key operating metrics described above, which are metrics we use to measure performance.
|
|
For the three months ended |
|
|
|
|
|
Change |
|
|||||||
|
|
2024 |
|
|
2023 |
|
|
Change |
|
|
% |
|
||||
(in thousands, unless otherwise indicated) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Natural Gas Total Revenues |
|
$ |
61,750 |
|
|
$ |
50,935 |
|
|
$ |
10,815 |
|
|
|
21.2 |
% |
Renewable Electricity Generation Total Revenues |
|
$ |
4,167 |
|
|
$ |
4,753 |
|
|
$ |
(586 |
) |
|
|
(12.3 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
RNG Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
CY RNG production volumes (MMBtu) |
|
|
1,392 |
|
|
|
1,380 |
|
|
|
12 |
|
|
|
0.9 |
% |
Less: Current period RNG volumes under fixed/floor- |
|
|
(389 |
) |
|
|
(327 |
) |
|
|
(62 |
) |
|
|
19.0 |
% |
Plus: Prior period RNG volumes dispensed in current |
|
|
360 |
|
|
|
367 |
|
|
|
(7 |
) |
|
|
(1.9 |
%) |
Less: Current period RNG production volumes not |
|
|
(308 |
) |
|
|
(320 |
) |
|
|
12 |
|
|
|
(3.8 |
%) |
Total RNG volumes available for RIN generation (1) |
|
|
1,055 |
|
|
|
1,100 |
|
|
|
(45 |
) |
|
|
(4.1 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
RIN Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Current RIN generation ( x 11.727) (2) |
|
|
12,374 |
|
|
|
12,898 |
|
|
|
(524 |
) |
|
|
(4.1 |
%) |
Less: Counterparty share (RINs) |
|
|
(1,185 |
) |
|
|
(1,351 |
) |
|
|
166 |
|
|
|
(12.3 |
%) |
Plus: Prior period RINs carried into current period |
|
|
4,707 |
|
|
|
2,967 |
|
|
|
1,740 |
|
|
|
58.6 |
% |
Less: CY RINs carried into next CY |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
0.0 |
% |
Total RINs available for sale (3) |
|
|
15,896 |
|
|
|
14,514 |
|
|
|
1,382 |
|
|
|
9.5 |
% |
Less: RINs sold |
|
|
(15,750 |
) |
|
|
(13,750 |
) |
|
|
(2,000 |
) |
|
|
14.5 |
% |
RIN Inventory |
|
|
146 |
|
|
|
764 |
|
|
|
(618 |
) |
|
|
(80.9 |
%) |
RNG Inventory (volumes not dispensed for RINs) (4) |
|
|
308 |
|
|
|
320 |
|
|
|
(12 |
) |
|
|
(3.8 |
%) |
Average Realized RIN price |
|
$ |
3.34 |
|
|
$ |
3.05 |
|
|
$ |
0.29 |
|
|
|
9.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Natural Gas Operating Expenses |
|
$ |
23,226 |
|
|
$ |
22,837 |
|
|
$ |
389 |
|
|
|
1.7 |
% |
Operating Expenses per MMBtu (actual) |
|
$ |
16.69 |
|
|
$ |
16.55 |
|
|
$ |
0.14 |
|
|
|
0.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
REG Operating Expenses |
|
$ |
3,170 |
|
|
$ |
2,753 |
|
|
$ |
417 |
|
|
|
15.1 |
% |
$/MWh (actual) |
|
$ |
77.32 |
|
|
$ |
57.35 |
|
|
$ |
19.97 |
|
|
|
34.8 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Electricity Generation Volumes Produced |
|
|
41 |
|
|
|
48 |
|
|
|
(7 |
) |
|
|
(14.6 |
%) |
Average Realized Price $/MWh (actual) |
|
$ |
101.63 |
|
|
$ |
99.02 |
|
|
$ |
2.61 |
|
|
|
2.6 |
% |
35
The following table summarizes our revenues, expenses and net income for the periods set forth below:
|
|
For the three months ended |
|
|
|
|
|
Change |
|
|||||||
|
|
2024 |
|
|
2023 |
|
|
Change |
|
|
% |
|
||||
Total operating revenues |
|
$ |
65,917 |
|
|
$ |
55,688 |
|
|
$ |
10,229 |
|
|
|
18.4 |
% |
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating and maintenance expenses |
|
|
15,484 |
|
|
|
14,212 |
|
|
|
1,272 |
|
|
|
9.0 |
% |
General and administrative expenses |
|
|
10,037 |
|
|
|
7,848 |
|
|
|
2,189 |
|
|
|
27.9 |
% |
Royalties, transportation, gathering and production fuel |
|
|
11,107 |
|
|
|
11,450 |
|
|
|
(343 |
) |
|
|
(3.0 |
)% |
Depreciation, depletion and amortization |
|
|
6,048 |
|
|
|
5,346 |
|
|
|
702 |
|
|
|
13.1 |
% |
Impairment loss |
|
|
533 |
|
|
|
51 |
|
|
|
482 |
|
|
|
945.1 |
% |
Total operating expenses |
|
|
43,209 |
|
|
|
38,907 |
|
|
|
4,302 |
|
|
|
11.1 |
% |
Operating income |
|
$ |
22,708 |
|
|
$ |
16,781 |
|
|
$ |
5,927 |
|
|
|
35.3 |
% |
Other expenses: |
|
|
1,695 |
|
|
|
1,039 |
|
|
|
656 |
|
|
|
63.1 |
% |
Net income before income taxes: |
|
|
21,013 |
|
|
|
15,742 |
|
|
|
5,271 |
|
|
|
33.5 |
% |
Income tax expense |
|
|
3,965 |
|
|
|
2,808 |
|
|
|
1,157 |
|
|
|
41.2 |
% |
Net income |
|
$ |
17,048 |
|
|
$ |
12,934 |
|
|
$ |
4,114 |
|
|
|
31.8 |
% |
Revenues for the Three Months Ended September 30, 2024 and 2023
Total revenues in the third quarter of 2024 were $65,917 an increase of $10,229 (18.4%) compared to $55,688 in the third quarter of 2023. The increase was primarily related to an increase in the number of RINs we self-marketed from 2024 RNG production in the third quarter of 2024 compared to the third quarter of 2023. In addition, realized RIN pricing increased approximately 9.5% during the third quarter of 2024 compared to the third quarter of 2023.
Renewable Natural Gas Revenues
We produced 1,392 MMBtu of RNG during the third quarter of 2024, an increase of 12 MMBtu (0.9%) compared to 1,380 MMBtu produced in the third quarter of 2023. Our Pico facility produced 27 MMBtu more in the third quarter of 2024 compared to the third quarter of 2023 as a result of commissioning our dairy digestion expansion project. Our Raeger facility produced 15 MMBtu more in the third quarter of 2024 compared to the third quarter of 2023 as a result of plant processing equipment improvements and increased inlet flows. Our Galveston and Coastal facilities produced 27 more MMBtu in the third quarter of 2024 compared to the third quarter of 2023 due to previously disclosed third quarter of 2023 dry weather conditions impacting gas feedstock availability. Our Rumpke facility produced 59 fewer MMBtu in the third quarter of 2024 compared to the third quarter of 2023 as a result of reduced feedstock inlet due to ongoing wellfield extraction environmental factors. Our Atascocita facility produced 22 fewer MMBtu in the third quarter of 2024 compared to the third quarter of 2023 as a result of weather driven utility outages which impacted our production.
Revenues from the Renewable Natural Gas segment in the third quarter of 2024 were $61,750, an increase of $10,815 (21.2%) compared to $50,935 in the third quarter of 2023. Average commodity pricing for natural gas for the third quarter of 2024 was $2.16 per MMBtu, 15.3% lower than the third quarter of 2023. During the third quarter of 2024, we self-monetized 15,750 RINs, representing a 2,000 increase (14.5%) compared to 13,750 in the third quarter of 2023. Average pricing realized on RIN sales during the third quarter of 2024 was $3.34 as compared to $3.05 in the third quarter of 2023, an increase of 9.5%. This compares to the average D3 RIN index price for the third quarter of 2024 of $3.36 as compared to $3.01 in the third quarter of 2023, an increase of approximately 11.6%. At September 30, 2024, we had approximately 308 MMBtu available for RIN generation and we had approximately 146 RINs generated and unsold. At September 30, 2023, we had approximately 320 MMBtu available for RIN generation and 764 RINs generated and unsold.
Renewable Electricity Generation Revenues
We produced approximately 41 MWh in Renewable Electricity in the third quarter of 2024, a decrease of 7 MWh (14.6%) from 48 MWh in the third quarter of 2023. Our Security facility produced approximately 5 MWh less in the third quarter of 2024 compared to the third quarter of 2023 as a result us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.
36
Revenues from Renewable Electricity facilities in the third quarter of 2024 were $4,167, a decrease of $586 (12.3%) compared to $4,753 in the third quarter of 2023. The decrease was primarily driven by the cessation of operations at our Security facility.
In the third quarter of 2024, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 100.0% in the third quarter of 2023. This provides us with certainty of price resulting from our Renewable Electricity sites.
Expenses for the Three Months Ended September 30, 2024 and 2023
General and Administrative Expenses
Total general and administrative expenses in the third quarter of 2024 were $10,037, an increase of $2,189 (27.9%) compared to $7,848 for the third quarter of 2023. Employee related costs, including stock-based compensation costs were $7,216 in the third quarter of 2024, an increase of $2,695 (59.6%) compared to $4,521 in the third quarter of 2023. The increase was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee. Our corporate insurance fees decreased approximately $262 (17.1%) in the third quarter of 2024 compared to the third quarter of 2023.
Renewable Natural Gas Expenses
Operating and maintenance expenses for our RNG facilities in the third quarter of 2024 were $12,586, an increase of $667 (5.6%) as compared to $11,919 in the third quarter of 2023. Our McCarty facility operating and maintenance expenses increased approximately $444 primarily related to the wellfield operational enhancements. Our Atascocita facility operating and maintenance expenses increased approximately $434 primarily related to an increase in utility expense and a property tax refund received in the third quarter of 2023. Our Pico facility operating and maintenance expenses increased approximately $197 as a result of timing of digester preventative maintenance. Our Apex facility operating and maintenance expenses decreased approximately $338 primarily related to the reduced utility expense and waste disposal costs. Our Coastal facility operating and maintenance expenses decreased approximately $197 primarily related to reduced utility expense and wellfield operational enhancements.
Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the third quarter of 2024 were $10,640, a decrease of $277 (2.5%) compared to $10,917 in the third quarter of 2023. We recorded a decrease to our Pico facility earnout of approximately 27.5% during the third quarter of 2024. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 17.2% for the third quarter of 2024 from 21.4% in the third quarter of 2023.
Renewable Electricity Expenses
Operating and maintenance expenses for our Renewable Electricity facilities in the third quarter of 2024 were $2,703, an increase of $483 (21.8%) compared to $2,220 in the third quarter of 2023. Our Magnolia facility operating and maintenance expenses increased approximately $458 as a result of non-capitalizable costs.
Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the third quarter of 2024 were $467, a decrease of $66 (12.4%) compared to $533 in the third quarter of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses remained unchanged at 11.2%.
Royalty Payments
Royalties, transportation, gathering, and production fuel expenses in the third quarter of 2024 were $11,107, a decrease of $343 (3.0%) compared to $11,450 in the third quarter of 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.
Depreciation
Depreciation and amortization in the third quarter of 2024 was $6,048, an increase of $702 (13.1%) compared to $5,346 in the third quarter of 2023. The increase was associated with timing of capital investment placed into service primarily driven by our Pico Digestion Capacity Increase project.
37
Impairment loss
We calculated and recorded impairment losses of $533 in the third quarter of 2024, an increase of $482 (945.1%) compared to $51 in the third quarter of 2023. The specifically identified impairments were for various RNG equipment that was deemed obsolete or inoperable for current operations and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. The third quarter of 2023 impairment related to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use and recorded in our RNG segment. None of the impairments were related to expected future cash flows.
Other Expenses
Other expenses in the third quarter of 2024 was $1,695, an increase of $656 (63.1%) compared to $1,039 in the third quarter of 2023. The increase was primarily related to an increase in interest expense of $540 from the third quarter of 2024 compared to the third quarter of 2023.
Income Tax Expense
Income tax expense for the three months ended September 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily related to vesting of restricted stock grants on stock compensation and the benefit from production tax credits.
The effective tax rate of 18.9% for the three months ended September 30, 2024 was higher than the rate for the three months ended September 30, 2023 of 17.8% primarily related to vesting of restricted stock grants on stock compensation and the benefit from production tax credits.
Operating Income (Loss) for the Three Months Ended September 30, 2024 and 2023
Operating income in the third quarter of 2024 was $22,708, an increase of $5,927 (35.3%) compared to $16,781 in the third quarter of 2023. RNG operating income for the third quarter of 2024 was $33,616, an increase of $9,553 (39.7%) compared to $24,063 in the third quarter of 2023. Renewable Electricity Generation operating loss for the third quarter of 2024 was $618, a decrease of $1,318 (188.3%) compared to operating income of $700 for the third quarter of 2023.
38
Comparison of Nine Months Ended September 30, 2024 and 2023
The following table summarizes the key operating metrics described above, which are metrics we use to measure performance.
|
|
For the nine months ended |
|
|
|
|
|
Change |
|
|||||||
|
|
2024 |
|
|
2023 |
|
|
Change |
|
|
% |
|
||||
(in thousands, unless otherwise indicated) |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Natural Gas Total Revenues |
|
$ |
134,575 |
|
|
$ |
114,328 |
|
|
$ |
20,247 |
|
|
|
17.7 |
% |
Renewable Electricity Generation Total Revenues |
|
$ |
13,467 |
|
|
$ |
13,769 |
|
|
$ |
(302 |
) |
|
|
(2.2 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
RNG Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
CY RNG production volumes (MMBtu) |
|
|
4,188 |
|
|
|
4,163 |
|
|
|
25 |
|
|
|
0.6 |
% |
Less: Current period RNG volumes under fixed/floor-price contracts |
|
|
(1,049 |
) |
|
|
(957 |
) |
|
|
(92 |
) |
|
|
9.6 |
% |
Plus: Prior period RNG volumes dispensed in current period |
|
|
358 |
|
|
|
368 |
|
|
|
(10 |
) |
|
|
(2.7 |
%) |
Less: Current period RNG production volumes not dispensed |
|
|
(308 |
) |
|
|
(320 |
) |
|
|
12 |
|
|
|
(3.8 |
%) |
Total RNG volumes available for RIN generation (1) |
|
|
3,189 |
|
|
|
3,254 |
|
|
|
(65 |
) |
|
|
(2.0 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
RIN Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Current RIN generation ( x 11.727) (2) |
|
|
37,403 |
|
|
|
38,167 |
|
|
|
(764 |
) |
|
|
(2.0 |
%) |
Less: Counterparty share (RINs) |
|
|
(3,726 |
) |
|
|
(4,002 |
) |
|
|
276 |
|
|
|
(6.9 |
%) |
Plus: Prior period RINs carried into current period |
|
|
108 |
|
|
|
739 |
|
|
|
(631 |
) |
|
|
(85.4 |
%) |
Less: CY RINs carried into next CY |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
Total RINs available for sale (3) |
|
|
33,785 |
|
|
|
34,904 |
|
|
|
(1,119 |
) |
|
|
(3.2 |
%) |
Less: RINs sold |
|
|
(33,639 |
) |
|
|
(34,140 |
) |
|
|
501 |
|
|
|
(1.5 |
%) |
RIN Inventory |
|
|
146 |
|
|
|
764 |
|
|
|
(618 |
) |
|
|
(80.9 |
%) |
RNG Inventory (volumes not dispensed for RINs) (4) |
|
|
308 |
|
|
|
320 |
|
|
|
(12 |
) |
|
|
(3.8 |
%) |
Average Realized RIN price |
|
$ |
3.25 |
|
|
$ |
2.59 |
|
|
$ |
0.66 |
|
|
|
25.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Natural Gas Operating Expenses |
|
$ |
63,835 |
|
|
$ |
59,057 |
|
|
$ |
4,778 |
|
|
|
8.1 |
% |
Operating Expenses per MMBtu (actual) |
|
$ |
15.24 |
|
|
$ |
14.19 |
|
|
$ |
1.05 |
|
|
|
7.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
REG Operating Expenses |
|
$ |
11,208 |
|
|
$ |
10,008 |
|
|
$ |
1,200 |
|
|
|
12.0 |
% |
$/MWh (actual) |
|
$ |
80.06 |
|
|
$ |
69.99 |
|
|
$ |
10.07 |
|
|
|
14.4 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Other Metrics |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Renewable Electricity Generation Volumes Produced (MWh) |
|
|
140 |
|
|
|
143 |
|
|
|
(3 |
) |
|
|
(2.1 |
%) |
Average Realized Price $/MWh (actual) |
|
$ |
96.19 |
|
|
$ |
96.29 |
|
|
$ |
(0.10 |
) |
|
|
(0.1 |
%) |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
(1) RINs are generated the month following the month gas is produced and dispensed. Volumes under fixed/floor arrangements generate RINs which we not self-market. |
|
|||||||||||||||
(2) One MMBtu of RNG has the same energy content as 11.727 gallons of ethanol, and thus may generate 11.727 RINs under RFS program. |
|
|||||||||||||||
(3) Represents RINs available to be self-marketed by us during the reporting period. |
|
|||||||||||||||
(4) Represents gas production on which RINs are not generated. |
|
|||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
39
The following table summarizes our revenues, expenses and net income for the periods set forth below:
|
|
For the nine months ended |
|
|
|
|
|
Change |
|
|||||||
|
|
2024 |
|
|
2023 |
|
|
Change |
|
|
% |
|
||||
Total operating revenues |
|
$ |
148,042 |
|
|
$ |
128,097 |
|
|
$ |
19,945 |
|
|
|
15.6 |
% |
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
Operating and maintenance expenses |
|
|
48,596 |
|
|
|
43,614 |
|
|
|
4,982 |
|
|
|
11.4 |
% |
General and administrative expenses |
|
|
28,202 |
|
|
|
26,069 |
|
|
|
2,133 |
|
|
|
8.2 |
% |
Royalties, transportation, gathering and production fuel |
|
|
26,702 |
|
|
|
25,588 |
|
|
|
1,114 |
|
|
|
4.4 |
% |
Depreciation, depletion and amortization |
|
|
17,305 |
|
|
|
15,792 |
|
|
|
1,513 |
|
|
|
9.6 |
% |
Impairment loss |
|
|
1,232 |
|
|
|
777 |
|
|
|
455 |
|
|
|
58.6 |
% |
Transaction costs |
|
|
61 |
|
|
|
86 |
|
|
|
(25 |
) |
|
|
(29.1 |
)% |
Total operating expenses |
|
|
122,098 |
|
|
|
111,926 |
|
|
|
10,172 |
|
|
|
9.1 |
% |
Operating income |
|
$ |
25,944 |
|
|
$ |
16,171 |
|
|
$ |
9,773 |
|
|
|
60.4 |
% |
Other expenses: |
|
|
3,036 |
|
|
|
3,341 |
|
|
|
(305 |
) |
|
|
(9.1 |
)% |
Net income before income taxes: |
|
|
22,908 |
|
|
|
12,830 |
|
|
|
10,078 |
|
|
|
78.6 |
% |
Income tax expense |
|
|
4,722 |
|
|
|
2,681 |
|
|
|
2,041 |
|
|
|
76.1 |
% |
Net income |
|
$ |
18,186 |
|
|
$ |
10,149 |
|
|
$ |
8,037 |
|
|
|
79.2 |
% |
Revenues for the Nine Months Ended September 30, 2024 and 2023
Total revenues in the first nine months of 2024 were $148,042, an increase of $19,945 (15.6%) compared to $128,097 in the first nine months of 2023. The increase was primarily related to an increase in Realized RIN pricing of approximately 25.5% during the first nine months of 2024 compared to the first nine months of 2023.
Renewable Natural Gas Revenues
We produced 4,188 MMBtu of RNG during the first nine months of 2024, an increase of 25 MMBtu (0.6%) over the 4,163 MMBtu produced in the first nine months of 2023. Our Pico facility produced 49 MMBtu more in the first nine months of 2024 compared to the first nine months of 2023 as a result of commissioning our dairy digestion expansion project. Our Coastal facility produced 95 MMBtu more in the first nine months of 2024 compared to the first nine months 2023 as a result of plant processing equipment improvements completed in 2023 and continued wellfield operational enhancements. Certain of our Houston, TX based operating sites were impacted by severe weather events during the first nine month of 2024 including multiple day extended outages from Hurricane Beryl in July 2024. We estimate that the impact from these specific storm events contributed to our volumes being reduced by approximately 100 MMBtu during the 2024 period.
Revenues from the Renewable Natural Gas segment in the first nine months of 2024 were $134,575, an increase of $20,247 (17.7%) compared to $114,328 in the first nine months of 2023. Average commodity pricing for natural gas for the first nine months of 2024 was $2.10 per MMBtu, 21.9% lower than the first nine months of 2023. During the first nine months of 2024, we self-monetized 33,639 RINs, representing a 501 decrease (1.5%) compared to 34,140 in the first nine months of 2023. Average pricing realized on RIN sales during the first nine months of 2024 was $3.25 as compared to $2.59 in the first nine months of 2023, an increase of 25.5%. This compares to the average D3 RIN index price for the first nine months of 2024 of $3.22 as compared to $2.40 in the first nine months of 2023, an increase of approximately 34.3%. At September 30, 2024, we had approximately 308 MMBtu available for RIN generation and we had approximately 146 RINs generated and unsold. At September 30, 2023, we had approximately 320 MMBtu available for RIN generation and 764 RINs generated and unsold.
Renewable Electricity Generation Revenues
We produced approximately 140 MWh in Renewable Electricity in the first nine months of 2024, a decrease of 3 MWh (2.1%) from 143 MWh in the first nine months of 2023. Our Tulsa facility produced approximately 2 MWh more in the first nine months of 2024 compared to the first nine months of 2023 as a result of engine component failures that occurred in the first nine months of 2023. Our Security facility produced approximately 5 MWh less in the first nine months of 2024 compared to the first nine months of 2023 as a result us ceasing operations in connection with the first quarter of 2024 sale of the gas rights back to the landfill host.
40
Revenues from Renewable Electricity facilities in the first nine months of 2024 were $13,467, a decrease of $302 (2.2%) compared to $13,769 in the first nine months of 2023. The decrease was primarily driven by the decrease in our Security facility production volumes.
In the first nine months of 2024, 100.0% of Renewable Electricity Generation segment revenues were derived from the monetization of Renewable Electricity at fixed prices associated with underlying PPAs, as compared to 99.9% in the first nine months of 2023. This provides us with certainty of price resulting from our Renewable Electricity sites.
Expenses for the Nine Months Ended September 30, 2024 and 2023
General and Administrative Expenses
Total general and administrative expenses were $28,202 for the first nine months of 2024, an increase of $2,133 (8.2%) compared to $26,069 for the first nine months of 2023. Employee related costs, including stock-based compensation costs were $18,306 in the first nine months of 2024, an increase of $3,479 (23.5%) compared to $14,827 in the first nine months of 2023. The increase was primarily related to the accelerated vesting of certain restricted share awards as a result of the termination of an employee. Our professional fees decreased approximately $1,514 (40.0%) in the first nine months of 2024 compared to the first nine months of 2023.
Renewable Natural Gas Expenses
Operating and maintenance expenses for our RNG facilities in the first nine months of 2024 were $38,629, an increase of $3,669 (10.5%) as compared to $34,960 in the first nine months of 2023. Our Rumpke facility operating and maintenance expenses increased approximately $1,092 primarily related to media change outs and disposal costs. Our McCarty facility operating and maintenance expenses increased approximately $933 primarily related to a wellfield operational enhancement program. Our Atascocita facility operating and maintenance expenses increased approximately $905 primarily related to increased utility expense.
Royalties, transportation, gathering and production fuel expenses for our RNG facilities for the first nine months of 2024 were $25,206, an increase of $1,109 (4.6%) compared to $24,097 in the first nine months of 2023. We recorded a reduction to our Pico facility earnout of approximately 10.0% during the first nine months of 2024. Royalties, transportation, gathering and production fuel expenses decreased as a percentage of RNG revenues to 18.7 % for the first nine months of 2024 from 21.1% for the first nine months of 2023.
Renewable Electricity Expenses
Operating and maintenance expenses for our Renewable Electricity facilities in the first nine months of 2024 were $9,712, an increase of $1,195 (14.0%) compared to $8,517 in the first nine months of 2023. Our Bowerman facility operating and maintenance expenses increased approximately $868 which was primarily driven by the timing of annual original equipment manufacturer preventative maintenance expenses. Our Magnolia facility operating and maintenance expenses increased approximately $840 as a result of non-capitalizable costs..
Royalties, transportation, gathering and production fuel expenses for our Renewable Electricity facilities for the first nine months of 2024 were $1,496, an increase of $5 (0.3%) compared to $1,491 in the first nine months of 2023. As a percentage of Renewable Electricity Generation segment revenues, royalties, transportation, gathering and production fuel expenses increased to 11.1% from 10.8%.
Royalty Payments
Royalties, transportation, gathering, and production fuel expenses in the first nine months of 2024 were $26,702, an increase of $1,114 (4.4%) compared to $25,588 in the first nine months of 2023. We make royalty payments to our fuel supply site partners on the commodities we produce and the associated Environmental Attributes. These royalty payments are typically structured as a percentage of revenue subject to a cap, with fixed minimum payments when Environmental Attribute prices fall below a defined threshold. To the extent commodity and Environmental Attributes’ prices fluctuate, our royalty payments may fluctuate upon renewal or extension of a fuel supply agreement or in connection with new projects. Our fuel supply agreements are typically structured as 20-year contracts, providing long-term visibility into the margin impact of future royalty payments.
41
Depreciation
Depreciation and amortization in the first nine months of 2024 was $17,305, an increase of $1,513 (9.6%) compared to $15,792 in the first nine months of 2023. The increase was associated with timing of capital investment placed into service related to our Pico digestion capacity increase and Raeger capital improvement projects.
Impairment loss
We calculated and recorded impairment losses of $1,232 in the first nine months of 2024, an increase of $455 (58.6%) compared to $777 in the first nine months of 2023. The impairment losses in the first nine months of 2024 primarily relate to the remaining book value of assets at the Security facility, various RNG equipment that was deemed obsolete for current operations, and REG assets that were impacted under initial startup testing for one of our REG construction work-in-progress sites. The first nine months of 2023 impairment related to specifically identified RNG machinery and feedstock processing equipment that were no longer in operational use.
Other Expenses
Other expenses in the first nine months of 2024 was $3,036, a decrease of $305 (9.1%) compared to $3,341 in the first nine months of 2023. The decrease was primarily related to proceeds received from the sale of gas rights ahead of the fuel supply agreement expiration of our Security facility which offset increased interest expense of $604.
Income Tax Expense
Income tax expense for the nine months ended September 30, 2024 was calculated using an estimated effective tax rate which differs from the U.S. federal statutory rate of 21.0% primarily due discrete events related to stock compensation as compared to the year to date pre-tax book income.
The effective tax rate was 20.6% for the nine months ended September 30, 2024 and 20.9% for the nine months ended September 30, 2023 as a result of both periods having discrete events related to the vesting of restricted stock grants on stock compensation as compared to the year to date pre-tax book income.
Operating Income (Loss) for the Nine Months Ended September 30, 2024 and 2023
Operating income in the first nine months of 2024 was $25,944, an increase of $9,773 (60.4%) compared to $16,171 in the first nine months of 2023. RNG operating income for the first nine months of 2024 was $56,911, an increase of $14,104 (32.9%) compared to $42,807 in the first nine months of 2023. Renewable Electricity Generation operating loss for the first nine months of 2024 was $2,210, an increase of $2,086 (1,682.3%) compared to $124 for the first nine months of 2023.
Non-GAAP Financial Measures:
The following table presents EBITDA and Adjusted EBITDA, non-GAAP financial measures, for each of the periods presented below. We present EBITDA and Adjusted EBITDA because we believe the measures assist investors in analyzing our performance across reporting periods on a consistent basis by excluding items that we do not believe are indicative of our core operating performance. In addition, EBITDA and Adjusted EBITDA are financial measurements of performance that management and the board of directors use in their financial and operational decision-making and in the determination of certain compensation programs. EBITDA and Adjusted EBITDA are supplemental performance measures that are not required by or presented in accordance with GAAP. EBITDA and Adjusted EBITDA should not be considered alternatives to net income (loss) or any other performance measure derived in accordance with GAAP, or as an alternative to cash flows from operating activities or a measure of our liquidity or profitability.
42
The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income, which is the most directly comparable GAAP measure, for the three months ended September 30, 2024 and 2023:
|
|
|
|
|
|
|
|
|
||
|
|
|
For the three months ended |
|
|
|||||
|
|
|
2024 |
|
|
2023 |
|
|
||
|
Net income |
|
$ |
17,048 |
|
|
$ |
12,934 |
|
|
|
Depreciation, depletion and amortization |
|
|
6,048 |
|
|
|
5,346 |
|
|
|
Interest expense |
|
|
1,835 |
|
|
|
1,295 |
|
|
|
Income tax expense |
|
|
3,965 |
|
|
|
2,808 |
|
|
|
Consolidated EBITDA |
|
|
28,896 |
|
|
|
22,383 |
|
|
|
|
|
|
|
|
|
|
|
||
|
Impairment loss (1) |
|
|
533 |
|
|
|
51 |
|
|
|
Net loss on sale of assets |
|
|
1 |
|
|
|
— |
|
|
|
Adjusted EBITDA |
|
$ |
29,430 |
|
|
$ |
22,434 |
|
|
|
|
|
|
|
|
|
|
|
||
The following table provides our EBITDA and Adjusted EBITDA for the periods presented, as well as a reconciliation to net income, which is the most directly comparable GAAP measure, for the nine months ended September 30, 2024 and 2023:
|
|
For the nine months ended |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Net income |
|
$ |
18,186 |
|
|
$ |
10,149 |
|
Depreciation, depletion and amortization |
|
|
17,305 |
|
|
|
15,792 |
|
Interest expense |
|
|
4,285 |
|
|
|
3,681 |
|
Income tax expense |
|
|
4,722 |
|
|
|
2,681 |
|
Consolidated EBITDA |
|
|
44,498 |
|
|
|
32,303 |
|
|
|
|
|
|
|
|
||
Impairment loss (1) |
|
|
1,232 |
|
|
|
777 |
|
Net loss of sale of assets |
|
|
72 |
|
|
|
37 |
|
Transaction costs |
|
|
61 |
|
|
|
86 |
|
Adjusted EBITDA |
|
$ |
45,863 |
|
|
$ |
33,203 |
|
Liquidity and Capital Resources
Sources of Liquidity
At September 30, 2024 and September 30, 2023, our cash and cash equivalents, net of restricted cash, was $54,973 and $73,304 respectively. We intend to fund development projects using cash flows from operations and borrowings under our revolving credit facility. We believe that we will have sufficient cash flows from operations and borrowing availability under our credit facility to meet our debt service obligations and anticipated required capital expenditures (including for projects under development) for the next 12 to 24 months. However, we are subject to business and operational risks that could adversely affect our cash flows and liquidity.
43
At September 30, 2024, we had debt before debt issuance costs of $58,000, compared to debt before debt issuance costs of $64,000 at December 31, 2023.
Our debt before issuance costs (in thousands) are as follows:
|
|
September 30, 2024 |
|
|
December 31, 2023 |
|
||
Term loan |
|
$ |
58,000 |
|
|
|
64,000 |
|
Revolving credit facility |
|
|
— |
|
|
|
— |
|
Debt before debt issuance costs |
|
$ |
58,000 |
|
|
$ |
64,000 |
|
Amended Credit Agreement
On December 21, 2021, the Company entered into the Fourth Amendment with Comerica and certain other financial institutions. The current credit agreement, which is secured by a lien on substantially all of our assets and assets of certain of our subsidiaries, provides for a five-year $80,000 term loan, a five-year $120,000 revolving credit facility, and a $75,000 accordion feature.
As of September 30, 2024, $58,000 was outstanding under the term loan and we had no outstanding borrowings under the revolving credit facility. The term loan amortizes in quarterly installments of $2,000 through 2024, then increases to $3,000 through 2026, with a final payment of $32,000 in late 2026 with an interest rate of 6.12% and 6.11% at September 30, 2024 and December 31, 2023, respectively. The revolving and term loans under the Amended Credit Agreement bore interest at the BSBY plus an applicable margin based on our Total Leverage Ratio (in each case, as those terms are defined in the Amended Credit Agreement) as of September 30, 2024. The BSBY will cease on November 15, 2024, and the current debt agreement was amended to utilize the SOFR, plus an applicable margin.
The Amended Credit Agreement contains customary covenants applicable to us and certain of our subsidiaries, including financial covenants. The Amended Credit Agreement is subject to customary events of default, and contemplates that we would be in default if, for any fiscal quarter (x) the average monthly D3 RIN price (as determined in accordance with the Amended Credit Agreement) is less than $0.80 per RIN and (y) the consolidated EBITDA for such quarter is less than $6,000. Consolidated EBITDA is defined under the Amended Credit Agreement as net income plus (a) income tax expense, (b) interest expense, (c) depreciation, depletion, and amortization expense, (d) non-cash unrealized derivative expense and (e) any other extraordinary, unusual, or non-recurring adjustments to certain components of net income, as agreed upon by Comerica in certain circumstances.
Under the Amended Credit Agreement, we are required to maintain the following ratios:
As of September 30, 2024, we were in compliance with all applicable financial covenants under the Amended Credit Agreement.
The Amended Credit Agreement replaced our prior credit agreements with Comerica and a portion of the proceeds of the term loan made under the Amended Credit Agreement were used by us to, among other things, fully satisfy an aggregate of $59,197 outstanding principal under such credit agreements. For additional information regarding the Amended Credit Agreement, see Note 12— Debt to our unaudited condensed consolidated financial statements.
Capital Expenditures
We have historically funded our growth and capital expenditures with our working capital, cash flow from operations and debt financing. We expect our non-development 2024 capital expenditures to range between $14,000 and $16,000. Our 2024 capital plans include annual preventative maintenance expenditures, annual wellfield expansion projects, other specific facility improvements, and information technology improvements. Additionally, we currently estimate that our existing 2024 development capital expenditures will range between $55,000 and $65,000. The refinement in our 2024 development capital range is primarily related to the aforementioned delay of our Bowerman RNG Project. The majority of our 2024 development capital expenditures are related to our ongoing development of Montauk Ag Renewables, the second Apex facility, and the Bowerman RNG project. Our Amended Credit Agreement provides us with a $120,000 revolving credit facility, with a $75,000 accordion option, providing us with access to
44
additional capital to implement our acquisition and development strategy. We are currently in various stages of discussions regarding a variety of strategic growth opportunities. Included amongst these opportunities are: approximately up to three LFG RNG, waste-water treatment RNG, and CNG distribution opportunities. If we ultimately enter into definitive agreements for any of these opportunities, we expect to incur material capital expenditures related to either acquisition costs or development costs, or both. As we continue to explore strategic growth opportunities and while we have entered into nonbinding letters of intent for certain of these opportunities, we provide no assurances that our plans related to any or all of these strategic opportunities will progress to definitive agreements. We believe that our existing cash and cash equivalents, cash generated from operations, and credit availability under our Amended Credit Agreement would allow us to pursue and close on our identified strategic growth opportunities in addition to the previously discussed non-development and development capital expenditures.
Cash Flow
The following table presents information regarding our cash flows and cash equivalents for the nine months ended September 30, 2024 and 2023:
|
|
For the nine months ended |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Net cash provided by (used in): |
|
|
|
|
|
|
||
Operating activities |
|
$ |
43,071 |
|
|
$ |
19,587 |
|
Investing activities |
|
|
(54,129 |
) |
|
|
(45,404 |
) |
Financing activities |
|
|
(7,755 |
) |
|
|
(6,054 |
) |
Net decrease in cash and cash equivalents |
|
|
(18,813 |
) |
|
|
(31,871 |
) |
Restricted cash, end of the period |
|
|
456 |
|
|
|
431 |
|
Cash and cash equivalents, end of period |
|
|
55,429 |
|
|
|
73,735 |
|
For the first nine months of 2024, we generated $43,071 of cash provided by operating activities compared to $19,587 in the first nine months of 2023. For the first nine months of 2024, income and adjustments to income from operating activities provided $46,737 compared to income and adjustments to income provided $35,915 in first nine months of 2023. Working capital and other assets and liabilities used $3,666 in the first nine months of 2024 compared to working capital and other assets and liabilities used $16,328 in the first nine months of 2023.
Our net cash flows used in investing activities has historically focused on project development and facility maintenance. Our capital expenditures for the first nine months of 2024 were $53,334, of which $24,977, $10,021, $7,871, $1,795, and $1,297 were related to the Montauk Ag Renewables in North Carolina, second Apex RNG facility, Bowerman RNG project, Blue Granite RNG project, and the Pico facility digestion capacity increase, respectively. We completed a land acquisition in Turkey, NC for 42 acres during the first nine months of 2024 for $820.
Our net cash flows used in financing activities of $7,755 for the first nine months of 2024 increased by $1,701 compared to cash used in financing activities in the first nine months of 2023 of $6,054.
Contractual Obligations and Commitments
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to the outstanding letters of credit described below. Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.
We have contractual obligations involving asset retirement obligations. See Note 8 in the unaudited condensed consolidated financial statements for further information regarding the asset retirement obligations.
We have contractual obligations under our debt agreement, including interest payments and principal repayments. See Note 12 in the unaudited condensed consolidated financial statements for further discussion of the contractual commitments under our debt agreements, including the timing of principal repayments. During the first nine months of 2024, we had approximately $2,185 of off-balance sheet arrangements of outstanding letters of credit. These letters of credit reduce the borrowing capacity of our revolving credit facility under our Amended Credit Agreement. Certain of our contracts require these letters of credit to be issued to provide additional performance assurances. There have been no draw downs on these outstanding letters of credit. During the first nine months of 2023, we did not have off-balance sheet arrangements other than outstanding letters of credit of approximately $2,505.
45
We have contractual obligations involving operating leases. We lease office space and other office equipment under operating lease arrangements, expiring in various years through 2033. See Note 18 in the unaudited condensed consolidated financial statements for further information related to the lease obligations.
We have other contractual obligations associated with our fuel supply agreements. The expiration of these agreements range between 3-19 years. The minimum royalty and capital obligation associated with these agreements range from $8 to $1,645.
Critical Accounting Policies and Estimates
Our unaudited condensed consolidated financial statements are prepared in conformity with GAAP and require our management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, costs and expenses and related disclosures. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results may differ from these estimates, and such estimates may change if the underlying conditions or assumptions change.
Revenue Recognition
Our revenues are comprised of renewable energy and the related Environmental Attribute sales provided under a variety of short-term and medium-term agreements with our customers. All revenue is recognized when we satisfy our performance obligation(s) under the contract (either implicit or explicit) by transferring the promised product to the customer either when (or as) the customer obtains control of the product. A performance obligation is a promise in a contract to transfer a distinct product or service to a customer. A contract’s transaction price is allocated to each distinct performance obligation. We allocate the contract’s transaction price to each performance obligation using the product’s observable market standalone selling price for each distinct product in the contract.
Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. As such, revenue is recorded net of allowances and customer discounts as well as net of transportation and gathering costs incurred. To the extent applicable, sales, value add, and other taxes collected from customers and remitted to governmental authorities are accounted for on a net (excluded from revenues) basis.
The nature of the Company’s contracts may give rise to several types of variable consideration, such as periodic price increases. This variable consideration is outside of the Company’s influence as the variable consideration is dictated by the market. Therefore, the variable consideration associated with the long-term contracts is considered fully constrained.
RINs
We generate D3 RINs through our production and sale of RNG used for transportation purposes as prescribed under the RFS program. Our operating costs are associated with the production of RNG. The RINs are government incentives that are generated through our renewable operating projects and not a result of physical attributes of our RNG production. The RINs that we generate are able to be separated and sold as credits independently from the energy produced. Therefore, no cost is allocated to the RIN when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred. We enter into forward commitments to transfer RINs. These forward commitments are based on D3 RIN index prices at the time of the commitment. Realized prices for RINs monetized in a year may not correspond directly to index prices due to the forward selling of commitments.
RECs
We generate RECs through our production and conversion of landfill methane into Renewable Electricity in various states, including California, Oklahoma, and Texas. These states have various laws requiring utilities to purchase a portion of their energy from renewable resources. Our operating costs are associated with the production of Renewable Electricity. The RECs are generated as an output of our renewable operating projects. The RECs that we generate are able to be separated and sold independently from the electricity produced. Therefore, no cost is allocated to the REC when it is generated. Revenue is recognized on these Environmental Attributes when there is an agreement in place to monetize the credits at an agreed upon price with a customer and transfer of control has occurred.
Income Taxes
We are subject to income taxes in the U.S. federal jurisdiction and various state and local jurisdictions. Tax regulations within each jurisdiction are subject to the interpretation of the related tax laws and regulations and require significant judgment to apply.
46
Our net deferred tax asset position is a result of fixed assets, intangibles, and tax credit carryforwards. The realization of deferred tax assets is dependent upon our ability to generate sufficient future taxable income during the periods in which those temporary differences become deductible, prior to the expiration of the tax attributes. The evaluation of deferred tax assets requires judgment in assessing the likely future tax consequences of events that have been recognized in our financial statements or tax returns and forecasting future profitability by tax jurisdiction.
We evaluate our deferred tax assets at reporting periods on a jurisdictional basis to determine whether adjustments to the valuation allowance are appropriate considering changes in facts or circumstances. As of each reporting date, management considers new evidence, both positive and negative, when determining the future realization of our deferred tax assets. We account for uncertain tax positions using a “more-likely-than-not” threshold for recognizing and resolving uncertain tax positions. The evaluation of uncertain tax positions is based on factors that include, but are not limited to, changes in tax law, the measurement of tax positions taken or expected to be taken in tax returns, the effective settlement of matters subject to audit, new audit activity and changes in facts or circumstances related to a tax position.
Intangible Assets
Separately identifiable intangible assets are recorded at their fair values upon acquisition. We account for intangible assets in accordance with ASC 350, Intangibles—Goodwill and Other. Finite-lived intangible assets include interconnections, customer contracts, and trade names and trademarks. The interconnection intangible asset is the exclusive right to utilize an interconnection line between the operating project and a utility substation to transmit produced electricity. Included in that right is full maintenance provided on this line by the utility. Intangible assets with finite useful lives are amortized on a straight-line basis over their estimated useful life. We evaluate our finite-lived intangible assets for impairment as events or changes in circumstances indicate the carrying value of these assets may not be fully recoverable. Events that could result in an impairment include, among others, a significant decrease in the market price or the decision to close a site.
If finite-lived or indefinite-lived intangible assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. The fair value is determined based on the present value of expected future cash flows. We use our best estimates in making these evaluations, however, actual future pricing, operating costs and discount rates could vary from the assumptions used in our estimates and the impact of such variations could be material.
Our assessment of the recoverability of finite-lived and indefinite-lived intangible assets is determined by performing monitoring assessment of the future cash flows associated with the underlying gas rights agreements. The cash flows estimates are performed at the operating unit level and based on the average remaining length of the gas rights agreements. Based on our analysis, we concluded the cashflows generated to be well in excess of the carrying amounts. Changes in market conditions related to the various price indexes used in estimating these cash flows could adversely affect these estimates.
Finite-Lived Asset Impairment
In accordance with FASB ASC Topic 360, Property, Plant and Equipment and intangible assets with finite useful lives are evaluated for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by comparing the carrying amount of an asset or asset group to future undiscounted cash flows expected to be generated by the asset or asset group. Such estimates are based on certain assumptions, which are subject to uncertainty and may materially differ from actual results, including considering project specific assumptions for long-term credit prices, escalated future project operating costs and expected site operations. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the fair value of the assets. Fair value is generally determined by considering (i) internally developed discounted cash flows for the asset group, (ii) third-party valuations, and/or (iii) information available regarding the current market value for such assets. We use our best estimates in making these evaluations and consider various factors, including future pricing and operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates and the impact of such variations could be material. We identified discrete events and recorded impairment of $1,232 and $777 for the nine months ended September 30, 2024 and 2023, respectively. See Note 3 in the unaudited condensed consolidated financial statements for further information related to asset impairments.
Emerging Growth Company
We are an emerging growth company, as defined in the JOBS Act. The JOBS Act allows emerging growth companies to delay the adoption of new or revised accounting standards until such time as those standards apply to private companies. We intend to utilize
47
these transition periods, which may make it difficult to compare our financial statements to those of non-emerging growth companies and other emerging growth companies that have opted out of the transition periods afforded under the JOBS Act.
Recent Accounting Pronouncements
For a description of our recently adopted accounting pronouncements and recently issued accounting standards not yet adopted, see Note 2 of our unaudited condensed consolidated financial statements in this report.
48
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no material changes since our disclosure in Quantitative and Qualitative Disclosures About Market Risk included as Item 7A in our 2023 Annual Report.
ITEM 4. CONTROLS AND PROCEDURES
Management’s Evaluation of Disclosure Controls and Procedures
Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) or 15d-15(e) under the Exchange Act, as of the end of the period covered by this quarterly report. Disclosure controls and procedures are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Our management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving their objectives, and management necessarily applies its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Our management, including our principal executive officer and principal financial officer, after evaluating the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report, concluded that as of such date, our disclosure controls and procedures were effective at a reasonable level of assurance.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting during our most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
49
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
From time to time, we and our subsidiaries may be parties to legal proceedings arising in the normal course of our business. We and our subsidiaries are currently not a party, nor is our property subject, to any material pending legal proceedings.
ITEM 1A. RISK FACTORS
We face a number of risks that could materially and adversely affect our business, results of operations, cash flow, liquidity, or financial condition. A discussion of our risk factors can be found in Part I, “Item 1A Risk Factors” in our 2023 Annual Report any of which could have a material effect on us.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Use of Proceeds from Sale of Registered Securities
On January 21, 2021, our Registration Statement on Form S-1, as amended (File No. 333-251312) (the “Registration Statement”), was declared effective by the SEC in connection with our IPO. The underwriter for the IPO was Roth Capital Partners. A total of 3,399,515 shares of our common stock were sold pursuant to the Registration Statement, which was comprised of (1) 2,702,500 shares of new common stock issued by the Company and (2) 697,015 shares of the Company’s common stock held by MNK. The 3,399,515 shares were sold at an offering price of $8.50 per share and resulting in net proceeds to the Company of approximately $15.0 million, after deducting the underwriting discount of approximately $1.6 million and offering expenses payable by the Company of approximately $6.2 million.
The IPO closed on January 26, 2021. No payments for such expenses were made directly or indirectly to (i) any of our officers or directors or their associates, (ii) any persons owning 10% or more of any class of our equity securities or (iii) any of our affiliates.
From the closing of the IPO through March 31, 2024, approximately $15.0 million of the net proceeds from the IPO have been used by Montauk for the following: the Montauk Ag Asset Acquisition in May 2021, the purchase of the real-estate and property in October 2021 related to Montauk Ag, and subsequent development activities related to Montauk Ag Renewables. An immaterial amount has been used relating to other possible acquisitions and projects. As of March 31, 2024, all net proceeds were used by the Company.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
50
ITEM 6. EXHIBITS
Exhibit Number |
|
Description |
|
|
|
|
|
|
|
|
|
10.14 |
|
|
|
|
|
31.1 |
|
|
|
|
|
31.2 |
|
|
|
|
|
32.1 |
|
|
|
|
|
32.2 |
|
|
|
|
|
101.INS |
|
Inline XBRL Instance Document–the instance document does not appear in the Interactive Data File as its XBRL tags are embedded within the Inline XBRL document |
|
|
|
101.SCH |
|
Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents |
|
|
|
104 |
|
Cover page formatted as Inline XBRL and contained in Exhibit 101 |
|
|
|
51
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
November 12, 2024 |
|
MONTAUK RENEWABLES, INC. |
|
|
|
|
|
|
|
By: |
/s/ SEAN F. MCCLAIN |
|
|
|
Sean F. McClain |
|
|
|
President and Chief Executive Officer (Principal Executive Officer) |
|
|
|
|
|
|
By: |
/s/ KEVIN A. VAN ASDALAN |
|
|
|
Kevin A. Van Asdalan |
|
|
|
Chief Financial Officer (Principal Accounting Officer) |
52